Crownbutte Wind Power, Inc. - FORM 10-K

Attached files

file	filename
EX-31.1 - Crownbutte Wind Power, Inc.	v181116_ex31-1.htm
EX-31.2 - Crownbutte Wind Power, Inc.	v181116_ex31-2.htm
EX-32.1 - Crownbutte Wind Power, Inc.	v181116_ex32-1.htm
EX-32.2 - Crownbutte Wind Power, Inc.	v181116_ex32-2.htm
EX-10.21 - Crownbutte Wind Power, Inc.	v181116_ex10-21.htm
EX-10.20 - Crownbutte Wind Power, Inc.	v181116_ex10-20.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended: December 31, 2009

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _______________ to _______________

Commission file number: 333-156467

Crownbutte Wind Power, Inc.

(Exact name of registrant as specified in its charter)

Nevada		20-0844584
(State or other jurisdiction of incorporation or organization)		(IRS Employer Identification No.)

111 5th Avenue NE, Mandan, ND		58554
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (701) 667-2073

Securities registered under Section 12(b) of the Act: None

Securities registered under Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes ¨ No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Exchange Act.

Yes ¨ No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ¨ No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a smaller reporting company. See the definitions of the “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer ¨	Accelerated Filer ¨
Non-Accelerated Filer ¨ (Do not check if a smaller reporting company)	Smaller reporting company x

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

On June 30, 2009, the last business day of the registrant’s most recently completed second fiscal quarter, 10,996,167 shares of its common stock, par value $0.001 per share (its only class of voting or non-voting common equity) were held by non-affiliates of the registrant. The market value of those shares was $6,047,891, based on the last sale price of $0.55 per share of common stock on that date. For this purpose, shares of common stock beneficially owned by each executive officer and director of the registrant and each beneficial owner of 10% or more of the common stock outstanding have been excluded because such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

As of April 14, 2010, there were 32,257,472 shares of the registrant’s common stock issued and outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

None.

TABLE OF CONTENTS

Item Number and Caption		Page

Forward-Looking Statements		3

PART I		4
1.	Business	4
1A.	Risk Factors	36
1B.	Unresolved Staff Comments	59
2.	Properties	59
3.	Legal Proceedings	61
4.	Submission of Matters to a Vote of Security Holders	62

PART II		62
5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	62
6.	Selected Financial Data	65
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	65
8.	Financial Statements and Supplemental Data	86
9.	Changes in and Disagreements with Accountants on Accounting, and Financial Disclosure	86
9A.[T]	Controls and Procedures	86
9B.	Other Information	87

PART III		88
10.	Directors, Executive Officers, and Corporate Governance	88
11.	Executive Compensation	90
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	93
13.	Certain Relationships and Related Transactions	93
14.	Principal Accountant Fees and Services	94

PART IV		95
15.	Exhibits and Financial Statement Schedules	95

FORWARD-LOOKING STATEMENTS

Various statements in this Annual Report, including those that express a belief, expectation or intention, as well as those that are not statements of historical fact, are “forward-looking statements” within the meaning of the United States Private Securities Litigation Reform Act of 1995. The forward-looking statements may include projections and estimates concerning the timing and success of specific projects, revenues, income and capital spending. We generally identify forward-looking statements with the words “believe,” “intend,” “expect,” “seek,” “may,” “should,” “anticipate,” “could,” “estimate,” “plan,” “predict,” “project” or their negatives, and other similar expressions. These statements are likely to address our growth strategy, financial results and exploration and development programs, among other things.

Forward-looking statements are subject to risks and uncertainties that may change at any time, and, therefore, our actual results may differ materially from those that we expected. The forward-looking statements contained in this Annual Report are largely based on our expectations, which reflect many estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe such estimates and assumptions are reasonable, we caution that it is very difficult to predict the impact of known factors and it is impossible for us to anticipate all factors that could affect our actual results. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report are not guarantees of future performance, and we cannot assure any reader that such statements will be realized or the forward looking events and circumstances will occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to the factors described in the “Risk Factors” section and elsewhere in this Annual Report. All forward-looking statements are based upon information available to us on the date of this Annual Report. We undertake no obligation to update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

In this Annual Report, unless the context requires otherwise, references to the “Company,” “Crownbutte,” “we,” “our” and “us” refer to Crownbutte Wind Power, Inc., a publicly traded Nevada corporation formerly known as ProMana Solutions, Inc., together with its subsidiaries, including Crownbutte Wind Power, Inc., a North Dakota corporation (“Crownbutte ND”).

PART I

ITEM 1.

BUSINESS

Overview of Our Business

Crownbutte ND was founded in 1999 by our Chief Executive Officer, Timothy H. Simons, with the goal of addressing the requirements of regional utility companies to satisfy increasing renewable energy demands. We develop wind parks from green field to operation, which we have sold to regional utilities. One park developed by us was purchased directly by Basin Electric Power Cooperative (2.6 megawatts (MW) near Chamberlain, South Dakota). We also developed a 20 MW, expandable to 50 MW, project in Baker, MT, which was sold at late brownfield stage to Montana-Dakota Utilities. In addition to these two operating parks, we have completed various consulting activities with regional utilities and international energy companies. Our ultimate goal is to develop, own and operate merchant wind parks in the 20 to 60 MW capacity range. Currently, we have 12 projects totaling approximately 638 MW (0 MW currently in operation) of prospective capacity in various phases of development primarily in North Dakota, South Dakota and Montana, with a total of over 40,000 acres under lease option. See “Properties.” Our project management team is also exploring other opportunities in this region.

Our principal executive offices are located at 111 5th Avenue NE, Mandan, ND 58554, and our telephone number is (701) 667-2073. Our website address is www.crownbutte.com.

Recent Developments

Earlier this year, the Company was notified by the Midwest Independent Systems Operator (MISO) that two of our projects were fast-tracked through the interconnection queue. The two projects, in Elgin, ND and Wibaux, MT, were the only projects fast-tracked by MISO out of nearly 150 projects in the region. Fast-tracking status increased the likelihood the Company would receive an interconnection agreement and be positioned to obtain financing and begin construction of those projects by the end of 2010 or early 2011. Both of these 20 MW projects may qualify for the U.S. Treasury Department renewable energy grant program created by the American Recovery and Reinvestment Act of 2009 (discussed elsewhere in this report), if an interconnection agreement is received, financing obtained, and at least 5% of construction begins before December 31, 2010. The grant amount for most wind projects is equal to 30% of the authorized capital costs of the project. These projects have entered the final definitive planning study of the transmission interconnection process, and we expect to obtain interconnection agreements by fall 2010.

As indicated in the accompanying consolidated financial statements and Management’s Discussion and Analysis of Financial Condition and Results of Operations section of this report, on February 15, 2010, the Company executed a non-binding term sheet with a private equity firm to provide $37.5 million debt financing for the Gascoyne I project. Terms of the financing would provide for an 80% ownership interest to the lender with the Company retaining a 20% stake in the special-purpose entity. The consummation of this financing is subject to, among other things, satisfactory completion by the lender of all necessary technical and legal due diligence and satisfactory negotiation of all required definitive agreements necessary or desirable to effect the transaction. We anticipate a construction completion and operational date by the end of 2010 or early 2011.

Corporate Information and History

We were incorporated in the State of Nevada on March 9, 2004, under the name ProMana Solutions, Inc. As ProMana Solutions, our business was to provide web-based, fully integrated solutions for managing payroll, benefits, human resource management and business processing outsourcing to small and medium sized businesses. Following the merger described below, we are no longer in that web services business.

On July 2, 2008, we amended our Articles of Incorporation to change our name to Crownbutte Wind Power, Inc.

Crownbutte ND was formed as a North Dakota limited liability company on May 11, 1999. On May 19, 2008, Crownbutte ND was converted to a North Dakota corporation.

On July 2, 2008, a special purpose acquisition subsidiary formed by us merged with and into Crownbutte ND, with Crownbutte ND surviving the merger, thereby becoming our wholly-owned subsidiary. Following the merger, we continued Crownbutte ND’s business operations. In connection with the merger, we changed our name to Crownbutte Wind Power, Inc. Upon the closing of the merger, the holders of all of the issued and outstanding shares of Crownbutte ND surrendered all of their shares and received shares of our common stock on a one-to-one basis. Also on the closing date, holders of issued and outstanding warrants to purchase shares of Crownbutte common stock received new warrants to purchase shares of our common stock, also on a one-to-one basis.

Pursuant to the merger, we ceased operating as a provider of web-based, fully integrated solutions for managing payroll, benefits, human resource management and business processing outsourcing, and acquired the business of Crownbutte ND to develop wind parks from green field to operation and has continued Crownbutte ND’s business operations as a publicly-traded company.

At the closing of the merger, each share of Crownbutte ND’s common stock outstanding was converted into one share of our Common Stock. As a result, an aggregate of 18,100,000 shares of our Common Stock were issued to the holders of Crownbutte ND’s common stock. In addition, warrants to purchase an aggregate of 10,600,000 shares of Crownbutte ND’s outstanding at the time of the merger became warrants to purchase an equivalent number of shares of our Common Stock.

The merger agreement contains a provision for a post-closing adjustment to the number of shares of our Common Stock issued to the former Crownbutte ND stockholders, in an amount up to 2,000,000 shares of our Common Stock, to be issued on a pro rata basis for any breach of the Merger Agreement by us, discovered during the one-year period following the closing. In order to secure the indemnification obligations of Crownbutte ND under the merger agreement, 5% of the shares of our Common Stock to which the former Crownbutte ND stockholders are entitled in exchange for their shares of Crownbutte ND in connection with the Merger will be held in escrow for a period of one year.

The merger agreement contained customary representations and warranties and pre- and post-closing covenants of each party and customary closing conditions. Breaches of the representations and warranties will be subject to customary indemnification provisions.

The merger was treated as a recapitalization of the Company for financial accounting purposes. Crownbutte ND is considered the acquirer for accounting purposes, and our historical financial statements before the merger have been replaced with the historical financial statements of Crownbutte ND before the merger in all subsequent filings with the Securities and Exchange Commission.

The parties have taken all actions necessary to ensure that the merger is treated as a tax-free exchange under Section 368(a) of the Internal Revenue Code of 1986, as amended.

Contemporaneously with the merger, the then-existing assets and liabilities of the Company were transferred to Pro Mana Technologies, Inc., a New Jersey corporation, which at that time was a wholly-owned subsidiary of the Company. Contemporaneously with the merger, we transferred all of the outstanding capital stock of Pro Mana Technologies to certain pre-merger shareholders of the Company in exchange for the surrender and cancellation of an aggregate of 144,702 shares of our common stock and warrants to purchase 19,062 shares of our common stock held by those stockholders and certain covenants and indemnities. We no longer own Pro Mana Technologies.

On July 31, 2008, we effected a reverse stock split, as a result of which each 65.723 shares of our common stock (including those issued in connection with the merger) then issued and outstanding were converted into one share of our common stock. Unless otherwise stated herein or the context clearly indicates otherwise, all share and per share numbers in this prospectus relating to our common stock have been adjusted to give effect to the reverse stock split.

General Philosophy

We have developed what we believe is a unique process for bringing viable wind parks to market. While most developers have focused on large projects of 100 MW or more, we have found a niche in the 20-60 MW range. Our focus will be to bring these smaller parks from concept to operation. The project sites currently in development by us are located directly on some of the most ideal wind regimes in the country, with net capacity factors of up to forty-six percent (46%). These above-average net capacity factors have a significant impact on the amount of electricity that can be generated and therefore on future revenues.

Net capacity factor is one element used in measuring the productivity of a wind turbine, wind energy project or any other power production facility. It compares the turbine’s production over a given period of time with the amount of power the turbine could have produced if it had run at full capacity for the same amount of time.

	Amount of power produced over time (usually measured annually)
Net Capacity Factor =
	Power that would have been produced if turbine operated at full capacity 100% of the time over the same period of time

Net capacity factors are calculated using the following inputs:

1)	The power curve for the specific turbine that is being used at a given project site. This comes from the turbine manufacturer and varies between turbine types.

The wind velocity distribution (Weibull Distribution) at the site of a given project. This comes from a statistical analysis of the meteorological data gathered from our proprietary meteorological towers erected at the site over the course of several years and confirmed with existing meteorological information from very long term weather stations and airport and other meteorological towers near the site.

3)	A mathematical model of the wind shear which allows us to extrapolate the wind speed data gathered from our meteorological towers at three different heights up to the specific hub-height of the wind turbine generator.

4)	Estimates of a number of known losses that are incurred during wind turbine operations. In particular, these are:

Topographic efficiency

Electrical efficiencies

Availability

Array losses

Icing and blade degradation

Substation maintenance

Utility downtime

Power curve turbulence variation

Sector management

We utilize proprietary computer software which incorporates each of these inputs for a given project site and returns the net capacity factor as its output.

This capacity factor is then verified against the net capacity factor calculated by an independent Certified Consulting Meteorologist (CCM) who is contracted for each project so that the net capacity factors are certified as correct and thus can be used in our interconnection requests and financing negotiations.

When our results differ from those of the Certified Consulting Meteorologist, it is due to different estimates in the above list of inputs. For example, the CCM may use a different Hellman exponent in the wind shear model than we do, or they may use different estimates of the loss factors. In these cases, the CCM net capacity factor is assumed to be correct, and we adjust our input assumptions to conform with those of the CCM.

Our net capacity factor projections are subject to change and are not intended to predict the wind at any specific time over the turbine’s 20-year useful life. Even if our predictions of a wind energy project’s net capacity factor become validated over time, the energy projects may experience hours, days, months, and even years that are below our wind resource projections.

Our focus on smaller projects allows us to install parks where developers of larger projects would be at a disadvantage, because smaller projects more easily fit into the current transmission grid, which decreases the costs of upgrading downstream components. While small projects are the focus of our strategy, we have not ruled out the possibility of larger projects.

Our business model focuses on the development of merchant parks. We do not plan to enter into power purchase agreements (PPAs) unless they are offered on favorable terms. Currently in the upper Midwest, with the exception of Minnesota, power purchase agreements tend to be difficult to obtain. When power purchase agreements are available, they tend to be at a price per kilowatt hour (kWh) that is less than the market price of electricity. Merchant parks sell electricity on the open market. Based on spot prices for electricity over the past five years, our merchant parks would have received on average $0.042 per kWh. Selling power on the open market increases the risk of the projects. However, based on U.S. Department of Energy forecasts and our own analysis, we believe that over the next decade the market price of electricity will continue to increase and that this merchant model will allows us to capture that upside potential.

In the past, we have been developing and then selling wind parks, in some cases remaining as a consultant for the party that purchased the park. We plan to continue to sell developments as a part of our ongoing business, but we intend to shift the focus of our business towards ownership and operation of merchant wind parks that we develop. We believe that this will allow us to grow our balance sheet and increase cash flow.

We intend to develop sites from “green field” (or blank slate) at a rate of approximately two to three additions to our pipeline per year, with each site likely to reach operation in approximately three years.

The first wind park that we plan to build, own and operate is a 20 MW project called Gascoyne I located south of Dickinson, North Dakota. As stated elsewhere in this report and the accompanying notes to audited consolidated financial statements, financing for the Gascoyne I park is pending due diligence and final approval by the lender and satisfactory negotiation of all required definitive agreements pursuant to a non-binding term sheet. Our goal is to have approximately 20 MW of owned operating capacity by the end of 2010 or early 2011, and we target the construction and commissioning of approximately 40 MW of owned operating capacity annually thereafter. We do not currently and do not plan to act as an operator of wind parks we do not own.

To successfully develop, build and own wind parks, and to acquire other developments or make business acquisitions, we will need to raise capital. We plan to raise approximately $1 million through private placements of equity by the end of 2010, the proceeds of which, together with cash on hand, will be used for general corporate expenses associated with the hiring of new staff required to accelerate our development activities, as well as move into our new owner-operator business model, which requires oversight of construction of projects, as well as the operations and maintenance of projects after construction is complete.

We anticipate that we will need to arrange turbine supply loans to finance approximately 60 to 90% of the cost of a project’s turbines. After we have developed a wind energy project that we intend to own to the point where we are prepared to commence construction, we will need to raise construction financing to retire turbine indebtedness and to pay construction costs. Construction loans are generally secured by the project’s assets and our equity interests in the project companies. In certain instances we may enter into a construction loan for a single project, while in other instances we may be able to finance multiple projects through a single credit facility. We will also use equity capital contributions (our own and potentially from other investors as described above) to fund a portion of each project’s construction costs.

It is important to note that we do not plan to enter into PPAs, unless they are offered at a favorable rate. Instead, we will be selling our electricity on the open market. This is a deviation from the standard business model of wind parks, where a PPA is entered into to guarantee a price for a period of time. In our geographic areas, utilities generally have not been interested in PPA agreements, except at unattractive rates. We believe we will benefit from the sale of electricity in the merchant model because of the higher average price relative to what would be offered by a utility.

Our growth strategy is focused on developing parks from green field to operation. Our project management team is constantly exploring new opportunities in the North Dakota, South Dakota and Montana area that appear to be optimal sites. For our business strategy to work, new locations with excellent potential must continually be found and developed. In addition to green field developments, we are constantly analyzing the late stage developments of other wind developers. If a project appears to be feasible, we will pursue the purchase of the park. The value of a wind project and the expected level of returns are a function of the electricity that can be produced and its expected sales value over the lifetime of a wind farm. As the probability of a viable project reaching operation increases the market value also increases for that project. Key parts of the development stage, such as acceptable wind data, an interconnection agreement and a power off take solution, add the most value to the development process.

Each project has a value as it progresses, and projects can be sold at any stage of development. In our experience, prices for projects under development can range from $10,000 a MW for an early development stage project to $150,000 a MW for a project ready to begin construction. Developers looking to sell development stage projects will usually receive a higher price per MW for the sale of an entire pipeline of projects.

We are proceeding with development of our project portfolio. These projects are in various stages of development with the most advanced project ready to begin construction. We have focused on siting projects to fit the existing transmission grid so that our projects will not be subject to major upgrade costs or delayed because the need for additional transmission lines. As a result of our “size to fit” emphasis we have a number of small to mid size projects spaced out across North Dakota, South Dakota and Montana. Another key aspect of the Crownbutte development process is our emphasis on obtaining land control and wind data prior to starting the interconnection studies. Completing this work prior to the interconnection studies increases the probability that a project will be successful if an interconnection agreement is secured.

Development carries significant risk. In total, the process of site development can take up to five years and cost $200,000 to $300,000. Every step in the development process must be met precisely to prevent project failure. As the project completes each step in the development process the risk of the project decreases.

Our development strategy has several phases, and each phase adds value as a site is developed. The development phase involves all the preparation for park installation, up to but not including construction. The steps of wind park development, construction and operation are listed below:

1.	Identify the transmission capacity suitable for a specific-sized park within the large but widely scattered transmission system. By starting with the available transmission capacity we decrease the risk of adverse transmission system upgrade costs.

2.	Conduct topographical studies to determine the most promising locations by using the available meteorological data. We use this information to determine the anticipated energy production and associated project economics.

3.	Configure an initial park array to determine the parameters of the park with regard to transmission capability.

4.	Procure the necessary land lease options under the park’s footprint.

Install site-specific meteorological instrumentation, which is always necessary to obtain site specific meteorological data. In some cases a meteorological tower is already on site, and historic data is therefore available. In most cases we will erect a meteorological tower for meteorological observation.

6.	Accumulate sufficient meteorological data.

7.	Select turbine type based on performance factors, availability and financeability.

8.	Prepare a wind report. Once sufficient meteorological data has been accumulated we will retain a certified consulting meteorologist to prepare a financeable wind report by a certified consulting meteorologist, which validates that the wind regime will support the project cash flow model.

Apply for local, state and federal permitting and transmission queue position. The permitting requirements for a project depend to a large extent on the location of the project. However, there are normally permitting considerations for zoning laws, wildlife protection, historical sites and use of air space.

10.

Secure interconnect agreements with utility and systems operator. Upon completion of the necessary system studies that follow an interconnection application we will know the upgrades necessary to tie into the transmission grid. Upon signing of an interconnection agreement we will be allowed to use the transmission grid to sell or wheel electricity.

11.	Prepare site design. Prior to construction, we will prepare the site design, which includes the geotechnical studies for the foundations.

12.	Execute turbine supply agreement. The turbine supply agreement dictates the relationship between the developer and a turbine manufacturer. It includes the turbine delivery time lines and the warranties on the turbines the manufacturer will provide.

13.	Retain construction subcontractors for each piece of the construction. These include high voltage work, crane use, access road construction, pouring of foundations, and all other necessary steps to complete the park.

14.	Prepare final site designs, including design of the high voltage systems, service roads, junction boxes, etc.

15.	Finalize project financing. Prior to construction the necessary arrangements for both construction financing and financing for the operational project must be secured. The financing normally includes some mix of developer equity, production tax credit (PTC) equity, and debt.

16.	Order long lead-time items such as the main step-up transformer and substation steel.

17.	Construction. Subcontractors will undertake all construction activities with oversight by us and the turbine manufacturer’s engineers. Construction on a 20 MW park generally takes 6-12 months. The majority of costs in developing a park are recognized during the construction phase.

18.	Turbine Commissioning. Once the turbines are erected, they will be tested for performance in line within the manufacturer’s specification. It the tests show the turbine is operation properly is will be commissioned and begin commercial operation.

19.	Operation & Maintenance. We will manage the operation of the project upon its commercial operation.

Our current pipeline of projects includes 12 projects totaling 638 MW (0 MW currently in operation) of potential capacity.

Buyers of Wind Parks

The mix of potential buyers changes as the size of wind projects increases. Different players in the market place only become interested when capital requirements for a project reach a certain level. Larger players need size to justify the time and expense required to construct or acquire projects. Smaller projects in the single to high teens of total megawatt output are usually owned by several different types of parties for specific reasons. Municipalities will purchase two to ten MW to generate some of their electricity needs from a renewable energy source. Utilities can also own small projects, usually as a result of a state mandate which requires the utility to generate a percentage of their electricity from renewable energy. In other cases a municipality may have a mandate to support community wind projects.

The midsize projects have the largest spectrum of potential buyers. These projects can range from 20 to 200 MW in size. Midsize projects benefit from economies of scale, and the projects become economically viable without the assistance of state mandates. Midsize projects are also more likely to fit into the existing transmission grid. As the projects get larger, the likelihood of needing substantial system upgrades increases. Midsize projects have a number of possible investors, ranging from utilities to financial institutions. Utilities generally prefer the midsize projects because they provide the generation necessary to address renewable energy portfolio standards, without buying more generation than is required. Financial institutions are attracted to the midsize projects because they are the right size for an efficient capital campaign. The projects are big enough that raising capital is worth their time and expense, but also the projects are small enough that an institution will not be over-exposed to the risks of one project. When a company is looking to create a portfolio of renewable energy assets, the midsize projects are most ideally suited to allow for diversification across geographic area, transmission systems and technology. According to the American Wind Energy Association, the average utility-scale wind project size in America is 60 MW. We are focusing on projects in the 20 to 60 MW range.

Large projects are 200 MW and greater. Only the biggest developers and financial institutions have an appetite for these projects. The capital requirements for these projects are upwards of $400 million. These projects are only viable when new transmission is being constructed specifically for the project or some other special arrangement for transmission is in place.

Wind Turbine and Construction Materials Supply

The growth of our business is dependent on the availability of turbines and turbine financing. Wind energy projects require delivery and assembly of turbines. Supply and logistical issues are of the utmost importance when developing a wind park. Over the past couple of years, demand for turbines has softened due to the 2008 financial market crisis. The industry is beginning to turn around and the rate of construction of projects has increased since the implementation of the U.S. Treasury Department renewable energy grant program as part of the American Recovery and Reinvestment Act of 2009. We have been contacted by various developers who have excess turbines at discounted prices and are evaluating the feasibility of purchasing some of these turbines with limited or no warranty. We are also looking at quotes from GE and from Gamesa (both established suppliers), as well as from DeWind (a newer entrant into the U.S. wind turbine market) and ACCIONA, for new turbines. We have seen some evidence of softening turbine prices and shorter delivery lead times as the financial market turmoil during the autumn of 2008 has slowed the installation of new wind capacity. We expect that the turbines we require for our project development schedule will be available on a timely basis provided that we are able obtain turbine financing. We may work with several turbine suppliers to meet our turbine needs.

In addition, spare parts for wind turbines and key pieces of electrical equipment will need to be available for the turbines we have in operation. When we purchase our turbines, we also enter into warranty agreements with the manufacturer. Along with turbines and electrical equipment, other construction materials, such as gravel, cement, and rebar are necessary for the construction of roads and foundations. The combination of all these issues makes it essential for us to maintain working relationships with all of our suppliers.

Demand for Electricity

The demand for electricity in the U.S. has been steadily increasing. It is estimated that demand for electricity will increase by 1.1% per year, resulting in over 5 billion kWh demanded by 2030 (U.S. Department of Energy Annual Energy Outlook 2008). According to the same source, the retail price of electricity is also expected to rise to an average price of 9.3 cents per kWh by 2009 (adjusted to 2006 dollars), and stabilize at a slightly lower level of 8.5 cents per kWh, or 14.2 cents in nominal currency.

As the U.S. continues in recession, all prices in the economy, including the price of electricity, will experience downward pressure. To the extent that Crownbutte intends to use open market venues (i.e., the “merchant” markets) to sell power, variability of electricity prices are a risk to profitability in the short term. Over the long term, the demand for electricity is driven by the number of consumers, the numbers of electricity-powered devices employed and the efficiency of those devices. There is indication that the U.S. economy is beginning to recover, although demand for electricity and increases in price may remain relatively flat for months, and potentially years to come.

The population of the U.S. continues to grow, and the popularity of electrical and electronic appliances has also continued to grow. In addition, there are trends that hint at the possibility of widespread adoption of electric cars and plug-in hybrids in the U.S. in coming years. While we expect the efficiency of all devices to improve over time (with innovation), we expect that the growing population, the popularity of consumer electronics, and the possible growth of electric vehicles to all combine to keep the price of electricity stable and growing moderately over time.

Industry Overview

Renewable energy is produced using resources that are naturally replenished, such as wind, sunlight, geothermal heat, tides and biofuels. Technologies that produce energy from these renewable sources (other than biofuels) are often referred to as “clean” or “green” as they produce few, if any, pollutants that negatively impact the environment. Comparatively, fossil fuels such as coal, natural gas and oil are exhaustible and release greenhouse gases such as carbon dioxide or other pollutants into the atmosphere during energy production. As a result of increased environmental awareness, the deployment of renewable energy technologies has grown rapidly during the past several years. According to the Energy Information Administration, 37% of new U.S. power generation capacity in 2007 consisted of renewable technologies, compared with only 2% in 2003. This increase is expected to continue, with the American Council on Renewable Energy forecasting renewable energy capacity to grow by a compounded annual growth rate between 9% and 11% through 2025, yielding a potential 550,000-700,000 MW of additional renewable capacity. At this rate, the United States could supply 25% of its electrical energy requirements with renewable energy by 2025.

According to the U.S. Department of State, wind energy is the fastest-growing renewable energy generation technology worldwide due to its cost efficiency, technological maturity and the wide availability of wind resources. We believe that it has the greatest potential among all renewable energy technologies for further growth in the United States. Although the United States has hydroelectric and geothermal resources, many potential hydroelectric sites have already been developed and geothermal production is confined by geographical limitations to only certain areas of the United States. In contrast, according to the American Wind Energy Association, or AWEA, the available untapped wind resources across the United States remain vast. Additionally, other renewable energy technologies, such as solar power, are currently less economically attractive than wind energy, and others, such as biofuels, emit particulates which have a greater negative impact on the environment than wind energy.

Growth in U.S. Wind Energy

We believe that the growth in U.S. wind energy will continue due to a number of key factors, including:

●

Increases in electricity demand coupled with the rising cost of fossil fuels used for conventional energy generation resulting in increases in electricity prices;

●

Heightened environmental concerns, creating legislative and popular support to reduce carbon dioxide and other greenhouse gases;

●

Regulatory mandates, such as state renewable portfolio standard programs, as well as federal tax incentives including production tax credits and accelerated tax depreciation;

●

Improvements in wind energy technology;

●

Increasing obstacles for the construction of conventional fuel plants; and

●

Abundant wind resources in attractive energy markets within the United States.

From its beginnings in California, wind energy in the United States has expanded steadily to 36 of the 50 states. As depicted on the maps below, the total installed capacity of U.S. wind parks increased by over 680% from 2,500 MW to over 19,500 MW between December 1999 and June 2008.

Source for December, 1999: U.S. Department of Energy.

Source for June, 2008: American Wind Energy Association.

According to the American Wind Energy (AWEA) 2009 Annual Wind Report, installed U.S. wind capacity increased by 8,545 MW (50.8%) in 2008 and by 5,249 MW (45.3%) in 2007. Despite this growth, wind energy generation still only represented just 1.26% of U.S. electricity supply in 2008, and we believe that the prospects for further growth are very favorable. Additionally, in May 2008, the U.S. Department of Energy published a feasibility report discussing the potential for wind power to provide up to 20% of U.S. electricity needs by 2030, which would require over 300,000 MW of cumulative installed wind capacity to meet this target.

Increases in Electricity Demand Coupled with the Rising Cost of Fossil Fuels Used for Conventional Energy Result in Increases in Electricity Prices

The demand for electricity has historically exhibited steady growth and has increased by a cumulative amount of 23% or 728 billion kWh from 1995 through 2007. According to the Energy Information Administration, electricity demand in the United States is forecasted to continue to grow at a steady long-term rate with a cumulative increase from 2007 through 2030 of 32%. Most of this demand has historically been supplied by coal- or natural gas-fired power plants, which accounted for 49% and 21%, respectively, of U.S. electrical power generation in 2007. In New York, New England, Texas and California, natural gas accounts for a significant portion of the electricity production, and this high usage, combined with the increased presence of natural gas-fired power plants, has made it the fuel that determines the price of power in these markets.

We believe that the significant volatility in commodity fuel prices has spurred demand for alternative fuels such as wind energy, although recent drops in natural gas prices may reduce some of this demand in the short term. The following two charts are indicative of the volatility in oil and gas prices in recent years.

Price of Crude Oil and Natural Gas

Monthly Average Spot Prices of West Texas Intermediate (WTI) Crude Oil, US$ per Barrel (through August 2009) – source: The Wall Street Journal

Monthly Average U.S. Natural Gas Price for Electric Power, US$ per thousand cubic feet (through May 2009) – source: U.S. Energy Information Administration

The following tables illustrate the price increases in retail electricity in the United Sates as a whole and in North Dakota.

Annual average retail electricity price, United States – source: U.S. Energy Information Administration

Annual average retail electricity price, North Dakota – source: U.S. Energy Information Administration

Wind energy, which has no fuel costs, has become much more competitive by comparison to traditional electricity generation sources, and has grown dramatically relative to other non-hydroelectric renewable sources (including biofuels, geothermal and solar) in recent years, as shown in the following two charts.

Comparative Cost of Electric Power Generation

Source: National Association of Regulatory Utility Commissioners. For each generation source, cost is calculated by taking the mid-point of the range described in the report by Lazard — “Levelized Cost of Energy Analysis — Version 2.0,” June 2008

United States Wind Generation Growth

Source: Energy Information Administration

Non-hydro renewables consist of wind, solar, geothermal and biomass.

Wind energy also offers an attractive method of managing commodity price risk while maintaining strict environmental standards, as it provides a stable, affordable hedge against the risk of increases in the price of coal, natural gas and other fuels over time. Increasing the use of wind energy also has the implied benefit of lowering overall demand for natural gas, particularly during winter peak demand.

We believe that concern over the recent volatility in fuel prices in the United States, coupled with the country’s significant dependence on fossil fuels, has been and will continue to be a factor in the political and social movement towards greater use of clean energy.

Heightened Environmental Concerns, Creating Legislative and Popular Support to Reduce Carbon Dioxide and Other Greenhouse Gases

The growing concern over global warming caused by greenhouse gas emissions has also contributed to the growth in the wind energy industry. According to the Intergovernmental Panel on Climate Change Fourth Assessment Report, experts have noted that eleven of the last twelve years (1995-2006) rank among the warmest years since 1850. Additionally, the global average sea level has risen at an average rate of 1.8 millimeters per year since 1961 and at 3.1 millimeters per year since 1993, due to the melting of glaciers, ice caps and polar ice sheets, coupled with thermal expansion of the oceans. The importance of reducing greenhouse gases has been recognized by the international community, as demonstrated by the signing and ratification of the Kyoto Protocol, which requires reductions in greenhouse gases by the 177 (as of March 2008) signatory nations. While the United States did not ratify the Kyoto Protocol, state-level initiatives have been undertaken to reduce greenhouse gas emissions. California was the first state to pass global warming legislation, and ten states on the east coast have signed the Regional Greenhouse Gas Initiative, which proposes to require a 10% reduction in power plant carbon dioxide emissions by 2019.

Substituting wind energy for traditional fossil fuel-fired generation would help reduce CO2 emissions due to the environmentally-friendly attributes of wind energy. According to the Energy Information Administration, the United States had the highest CO2 emissions of all countries in the world in 2005, contributing approximately 20% of the world’s CO2 emissions. Since 1990, CO2 emissions from the United States’ electric power industry have increased by a cumulative amount of 27%, from 1.9 billion metric tons to 2.5 billion metric tons.

Indexed Electric Power Industry CO 2 Emissions: 1990–2006

Source: Energy Information Administration

1990: 100% = 1.9 Billion Metric Tons of CO2

Environmental legislation and regulations provide additional incentives for the development of wind energy by increasing the marginal cost of energy generated through fossil-fuel technologies. Such legislation and regulations have been designed to, for example, reduce ozone concentrations, particulate emissions, haze and mercury emissions and can require conventional energy generators to make significant expenditures, implement pollution control measures or purchase emissions credits to meet compliance requirements. These measures have increased fossil fuel-fired generators’ capital and operating costs and put upward pressure on the market price of energy. Because wind energy producers are price takers in energy markets, these legislative measures effectively serve to make the return on wind energy more attractive relative to other sources of generation.

We believe there is significant support in the United States to enact legislation that will attempt to reduce the amount of carbon produced by electrical generators. Although the ultimate form of legislation is still being debated, the two most likely alternatives are (i) a direct emissions tax or (ii) a cap-and-trade regime. We believe either of these alternatives would likely result in higher overall power prices, as the marginal cost of electricity in the United States is generally set by carbon intensive generation assets which burn fossil fuels such as oil, natural gas and coal. As a non-carbon emitter and a market price taker, we are positioned to benefit from these higher power prices.

Regulatory Mandates, Such as State Renewable Portfolio Standard Programs, as Well as Federal Tax Incentives Including Production Tax Credits and Accelerated Tax Depreciation

Growth in the U.S. wind energy market has also been driven by state and federal legislation designed to encourage the development and deployment of renewable energy technologies. This support includes:

●

Renewable Portfolio Standards. In response to the push for cleaner power generation and more secure energy supplies, many states have enacted renewable portfolio standard programs. These programs either require electric utilities and other retail energy suppliers to produce or acquire a certain percentage of their annual electricity consumption from renewable power generation resources, or, as the case in New York, designate an entity to administer the central procurement of renewable energy certificates for the state. Wind energy producers generate renewable energy certificates due to the environmentally beneficial attributes associated with their production of electricity.

The number of states with renewable portfolio standard programs has doubled in the last six years and as of August 2008, 32 states and the District of Columbia had adopted some form of renewable portfolio standard program. The District of Columbia and 26 of the 32 states have mandatory renewable portfolio standard requirements and combined, these 26 states represent over 50% of total U.S. electrical load. A number of states, including Arizona, California, Colorado, Massachusetts, Nevada, New Jersey, New Mexico and Texas have been so successful in meeting their original renewable portfolio standard targets that they have revised their programs to include higher targets. Among the states in which we currently have projects, Texas and Montana have renewable portfolio standards. Other states such as Missouri, North Dakota, South Dakota, Utah, Vermont and Virginia have adopted state goals, which set targets, not requirements, for certain percentages of total energy to be generated from renewable resources. The states that have adopted renewable portfolio standard programs or set state goals, as well as the related requirements or targets, are set forth in the following map.

U.S. Renewable Portfolio Standard Programs and Goals for Renewable Energy Generation

Source: Database of State Incentives for Renewables & Efficiency, August 2008.

RE – Renewable Energy.

IOUs – Investor-Owned Utilities.

Xcel – Xcel Energy, an electric and gas company that operates in the Midwest.

Class I Renewables – Electricity derived from solar, wind, wave or tidal action, geothermal, landfill gas, anaerobic digestion, fuel cells using renewable fuels, and certain other forms of sustainable biomass.

Co-op – Customer-owned electric utility that distributes electricity to its members.

Munis – Municipalities.

●

Almost every state that has implemented a renewable portfolio standard program will need considerable additional renewable energy capacity to meet its renewable portfolio standard requirements. Much of Emerging Energy Research’s forecasted 50,000 MW of installed wind capacity by 2015 will be driven by current and proposed renewable portfolio standard targets, along with additional demand from states without renewable standards.

●

Renewable Energy Certificates (“RECs”). A renewable energy certificate is a stand-alone tradable instrument representing the attributes associated with one MWh of energy produced from a renewable energy source. These attributes typically include reduced air and water pollution, reduced greenhouse gas emissions and increased use of domestic energy sources. Many states use renewable energy certificates to track and verify compliance with their renewable portfolio standard programs. Retail energy suppliers can meet the requirements by purchasing renewable energy certificates from renewable energy generators, in addition to producing or acquiring the electricity from renewable sources. Under many renewable portfolio standard programs, energy providers that fail to meet renewable portfolio standard requirements are assessed a penalty for the shortfall, usually known as an alternative compliance payment. Because renewable energy certificates can be purchased to satisfy the renewable portfolio standard requirements and avoid an alternative compliance payment, the amount of the alternative compliance payment effectively sets a cap on renewable energy certificate prices. In situations where renewable energy certificate supply is short, renewable energy certificate prices approach the alternative compliance payment, which in several states is in the $50-$59/MWh range. As a result, renewable energy certificate prices can rival the price of energy and renewable energy certificates can represent a significant additional revenue stream for wind energy generators.

●

Production Tax Credits. The production tax credit provides wind energy generators with a credit against federal income taxes, annually adjusted for inflation, for a duration of ten years from the date that the wind turbine is placed into service. In 2008, the production tax credit was $20.78/MWh. Wind energy generators with insufficient taxable income to benefit from the production tax credit may take advantage of a variety of investment structures to monetize the tax benefits.

The production tax credit was originally enacted in 1992 for wind parks placed into service after December 31, 1993 and before July 1, 1999. The production tax credit subsequently has been extended five times, but has been allowed to lapse three times (for periods of three, six and nine months) prior to retroactive extension. Currently, the production tax credit is scheduled to expire on December 31, 2012, unless an extension or renewal is enacted into law.

●

Accelerated Tax Depreciation. Tax depreciation is a non-cash expense meant to approximate the loss of an asset’s value over time and is generally the portion of an investment in an asset that can be deducted from taxable income in any given tax period. Current federal income tax law requires taxpayers to depreciate most tangible personal property placed in service after 1986 using the modified accelerated cost recovery system under which taxpayers are entitled to use the 200% or 150% declining balance method depending on the class of property, rather than the straight line method. In addition, under the modified accelerated cost recovery system, a significant portion of wind park assets is deemed to have depreciable life of five years which is substantially shorter than the 15 to 20 year depreciable lives of many non-renewable power supply assets. This shorter depreciable life and the accelerated depreciation method results in a significantly accelerated realization of tax depreciation for wind parks compared to other types of power projects. Wind energy generators with insufficient taxable income to benefit from this accelerated depreciation often monetize the accelerated depreciation, along with the production tax credits, through forming a limited liability company with third parties.

Improvements in Wind Energy Technology

Wind turbine technology has improved considerably in recent years with significant increases in capacity and efficiency. Multiple types and sizes of turbines are now available to suit a wide range of wind resource characteristics and landscapes. Modern wind turbines are capable of generating electricity for 20 to 30 years.

There have been two major trends in the development of wind turbines in recent years:

●	According to the Danish Wind Industry Association and the U.S. Department of Energy, individual turbine capacity has increased dramatically over the last 25 years, with 30 kW machines that operated in 1980 giving way to the 1.5 MW machines that are standard today; and

●

Wind park performance has improved significantly, according to the U.S. Department of Energy, as turbines installed in 2004 through 2006 averaged a 33%-35% net capacity factor (the ratio of the actual output over a period of time and the output if the wind park had operated at full capacity over that time period) as compared to the 22% net capacity factor realized by turbines installed prior to 1998.

Additionally, as wind energy technology has continued to improve, according to AWEA, the capital cost of wind energy generation has fallen by approximately 80% over the past 20 years.

Increasing Obstacles for the Construction of Conventional Fuel Plants

In addition to the impediments presented by the extensive and growing environmental legislation, new power plants that use conventional fuels, such as coal and nuclear technologies, face a difficult, lengthy and expensive permitting process. Furthermore, increasing opposition from public environmental groups towards coal-fired power plants, coupled with rising construction costs, contributed to the cancellation of many planned coal plants in 2007. According to Resource Media, a public relations firm representing environmental groups in the western United States, the construction of 31 coal-fired plants totaling 24,250 MW was canceled or delayed in 2007. As a result, despite increasing gross margins, only about 2,000 MW of net new capacity from coal and nuclear plants was brought online between 2003 and 2006. Additionally, in October 2007, the Kansas Department of Health and Environment became the first government agency in the United States to cite carbon dioxide emissions as the reason for rejecting an air permit for a proposed coal-fired electricity generating plant, saying that the greenhouse gas threatens public health and the environment. Traditional energy developers and utilities are likely to face similar permitting and restricted supply issues in the future. As a result, alternative energy sources such as wind will need to be developed to meet increasing electricity demand and will be able to capitalize on the resulting higher energy prices.

Abundant Wind Resources in Attractive Energy Markets within the United States

The potential for future growth in the U.S. wind energy market is supported by the large land area available for turbine installations and the availability of significant wind resources. According to AWEA, annual average wind speeds of 11 miles per hour or greater are required for grid-connected wind parks. As shown in the map below, a large portion of the United States exhibits wind speeds sufficient for wind park development.

Source: United States Department of Energy—National Renewable Energy Laboratory.

A chart describing the potential for wind power in billions of kWh is included below. Note that according to this source, North Dakota offers the best wind resource in the United States. The wind is exceptional in the Great Plains (and North Dakota especially), the actual installed capacity is minimal. Assuming a net capacity factor of 35%, current North Dakota wind parks only generate a small fraction of the state’s potential output. In fact, even with the projects planned for construction in the next year, less than 1% of potential will be realized.

THE TOP TWENTY STATES

for Wind Energy Potential

as measured by annual energy potential in the billions of kWh, factoring in environmental and land use exclusions for wind class of 3 and higher.

		B kWh/Yr			B kWh/Yr
1.	North Dakota	1,210	11 .	Colorado	481
2.	Texas	1,190	12 .	New Mexico	435
3 .	Kansas	1,070	13 .	Idaho	73
4 .	South Dakota	1,030	14 .	Michigan	65
5.	Montana	1,020	15.	New York	62
6.	Nebraska	868	16.	Illinois	61
7.	Wyoming	747	17 .	California	59
8 .	Oklahoma	725	18 .	Wisconsin	58
9.	Minnesota	657	19.	Maine	56
10.	Iowa	551	20.	Missouri	52

Source: An Assessment of the Available Windy Land Area and Wind Energy Potential in the Contiguous United States, Pacific Northwest Laboratory, August 1991. PNL-7789

Wind Energy Fundamentals

The term “wind energy” refers to the process used to generate electricity through wind turbines. The turbines convert wind’s kinetic energy into electrical power by capturing it with a three blade rotor mounted on a nacelle that houses a gearbox and generator. When the wind blows, the combination of the lift and drag of the air pressure on the blades spins the blades and rotor, which turns a shaft through the gearbox and generator to create electricity.

Wind turbines are typically grouped together in what are often referred to as “wind parks.” Electricity from each wind turbine travels down a cable inside its tower to a collection point in the wind park and is then transmitted to a substation for voltage step-up and delivery into the electric utility transmission network, or “grid.” Today’s wind turbines can efficiently generate electricity when the wind speed is between 11 and 55 miles per hour.

A key factor in the success of any wind park is the profile and predictability of the wind resources at the site. Extensive studies of historical weather and wind patterns have been performed across North America and many resources, in the forms of charts, graphs and maps, are available to wind energy developers. The most attractive wind park sites offer a combination of land accessibility, power transmission, proximity to construction resources and strong and dependable winds.

When wind energy developers identify promising sites, they perform detailed studies to provide greater certainty with respect to the long-term wind characteristics at the site and to identify the most effective turbine siting strategy. The long-term annual output of a wind park is assessed through the use of on-site wind data, publicly available reference data and sophisticated software. Wind speeds are estimated in great detail for specific months, days or even hours, and are then correlated to turbine manufacturers’ specifications to identify the most efficient turbine for the site. Additional calculations and adjustments for turbine availability (which is principally affected by planned and unplanned maintenance events), wake effects (wind depletion caused by turbines sited upwind), blade soiling and icing and other factors are made to arrive at an estimate of net expected annual kilowatt hour electricity production at the site.

Sources of Revenue for Wind Generators

Wind energy generators primarily derive revenue from three sources:

Energy sales. Energy sales are derived from the sale of energy into a wholesale market or to a specific customer, such as a utility or power marketer;

Renewable energy certificate sales. In many states, conventional energy producers are required either to produce a certain percentage of their energy from renewable sources or to purchase renewable energy certificates from renewable energy producers. Renewable energy certificates represent the environmental attributes associated with electricity from renewable sources. Renewable energy certificates are a tradable instrument that can be sold separately from the electricity produced by a renewable generation source, thereby providing an additional revenue stream; and

Capacity sales. In some states, but not the states in which we are developing wind parks, payments are made to energy generators, including wind parks, as a market incentive to promote the development and continued operation of capacity sufficient to meet regional load and reserve requirements. Market systems have been established to ensure that generators receive these payments based on their availability to generate electricity. Payments are generally allocated to wind parks based on the previous year’s capacity for the super-peak hours during winter and summer qualifying periods.

Crownbutte’s Portfolio Management

We have been involved with all stages of the development process for wind energy projects. We believe this experience has given us knowledge to develop wind energy projects efficiently and effectively. We seek to develop well sited and well planned wind energy projects. Revenues generated in the past from the sale of brown-field and completed projects have been reinvested into our project portfolio by continuing to develop additional projects. Selling developed projects prior to construction provides returns for the capital invested in the development process. However, the sale is a onetime occurrence from the developer’s standpoint, and developing projects just to sell them is a relatively high risk business strategy.

Operating wind projects allows the project owner to receive revenues over the life of a project. We view ownership and operation of wind energy projects as the next step in our expansion strategy. We believe that operational projects will provide the Company with better risk adjusted returns on capital. Ownership may also give us upside potential if electricity prices continue to rise or if the value of an operational wind energy project increases. We anticipate that both of these values will continue to increase over the long term, as they have in the past several years.

The upside potential for ownership in wind energy projects is driven mainly by the price of electricity. A wind energy project receives payment for the power it generates in one of two ways: either through a power purchase agreement (PPA) or selling into an open market for electricity. The PPA is the most common method of power off-take for wind energy projects. The agreements are almost always with a utility and normally require the utility to buy all electricity a project may generate at a set rate. The agreements normally have a price increase every year and can run for up to 20 years. The PPA rates are usually below the market rate for electricity. The guaranteed price that a PPA offers reduces the risk of a project. Additionally projects with PPAs will usually be able to secure higher levels of debt financing and/or lower interest rates on the debt.

In many areas of the country another viable strategy for power off-take is to sell the electricity into a power spot market. Projects that sell electricity in this manner are referred to as “merchant” projects. There are several systems that provide real time and day-ahead spot markets for electricity such as Midwest ISO, PJM, ERCOT and Cal ISO. To decrease risk and increase financing options, some projects will sell into the spot markets but hedge their exposure with electricity futures contracts that trade on exchanges like the NYMEX.

Our portfolio of projects is located in the Midwest, and therefore our merchant projects would sell into the Midwest ISO’s spot market. We view selling power from our projects into the MISO market as a better off-take strategy than a PPA. This view is based on the fact that we believe the price of electricity will continue to rise and that a merchant project model will allow us to most effectively participate in upward price movement. The historically increasing costs are reflected in the year-over-year rise in the spot price on the MISO market. See the chart under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Our Strategy.” As the U.S. continues in recession, all prices in the economy, including the price of electricity, will experience downward pressure. To the extent that Crownbutte intends to use open market venues (i.e., the “merchant” markets) to sell power, variability of electricity prices are a risk to profitability in the short term. Over the long term, the demand for electricity is driven by the number of consumers, the numbers of electricity-powered devices employed and the efficiency of those devices.

We continue to identify new green-field sites to build our pipeline of projects. Upon successfully reaching commercial operation with a project, we will continually evaluate the most ideal mix of projects in the portfolio. In the event a buyer is identified and the sale of a project would, in our judgment, provide better returns than operation, the project may be sold off after it is in commercial operation. The sale of projects could be used to assist in the financing of additional projects that may provide higher returns for the Company.

Regulation

The following is a summary overview of certain applicable regulations in the United States and should not be considered a full statement of the law or all related issues.

Energy Regulation

FPA

Under the Federal Power Act, or “FPA”, the Federal Energy Regulatory Commission (“FERC”) has exclusive rate-making jurisdiction over wholesale sales of electricity and transmission in interstate commerce. The FPA subjects “public utilities” within the meaning of the FPA, among other things, to rate and corporate regulation by FERC. In particular, sellers of electricity at wholesale in interstate commerce and transmitters of electricity in interstate commerce are regulated by FERC with respect to: the review of the terms and conditions of wholesale electricity sales and transmission of electricity; the need to obtain advance approval of certain dispositions of public utility facilities, mergers, purchases of securities of other public utilities, acquisitions of existing generation facilities and changes in upstream ownership interests; the regulation of their borrowing and securities issuances and assumption of liabilities; and the review of interlocking directorates. Future issuances of our equity securities may be subject to FERC approval under Section 203 of the FPA. FERC has authority under Section 206 of the FPA in certain circumstances to order refunds and, under FPA amendments pursuant to the Energy Policy Act of 2005, FERC has expanded authority to assess civil penalties of up to $1 million per day for violations of the FPA. We can offer no assurance that, at some future time, the U.S. Congress will not change the relevant provisions of the FPA, or that FERC will not change its regulations implementing the requirements of the FPA.

Wholesale electricity sellers authorized by FERC to sell at market-based rates may obtain waivers or blanket pre-approvals as to certain of the regulatory requirements of the FPA, including waiver of FERC’s accounting regulations and blanket pre-authorization with respect to its regulation of issuances of securities and assumption of liabilities. We can offer no assurance that FERC will not revisit its policies at some future time with the effect of limiting market-based rate authority, regulatory waivers and blanket authorizations. We have been granted market-based rate authority for one project to date and are familiar with the legal procedures and requirements to be granted market-based rate authority. Therefore, we expect our wind parks to be granted market-based rate authority, and as a result, to be permitted to sell electric energy and capacity at market or otherwise negotiated rates. Wind parks with market-based rate authorization are subject to regulation by FERC as a “public utility” pursuant to the FPA. FERC’s orders that grant market-based rate authority reserve the right to revoke or revise that authority if FERC subsequently determines that the market-based rate seller can exercise market power in transmission or generation, create barriers to entry or engage in abusive affiliate transactions. FERC may impose various forms of market mitigation measures, including price caps and operating restrictions, where it determines market power may exist and that the public interest requires such potential market power to be mitigated. Such wind parks are also required to report to FERC any material changes in status that would reflect a departure from the characteristics that FERC relied upon when granting market-based rate authority, make quarterly electronic filings with FERC providing information on sales of electricity and comply with market behavior and manipulation rules. If any of our wind parks were to be unable to obtain, or were to lose once obtained, its market-based rate authority, it would be required to obtain FERC’s acceptance of cost-of-service rate schedules and would become subject to the accounting, record-keeping and reporting requirements that are imposed on utilities with cost-based rate schedules.

In addition to direct regulation by FERC, our wind parks will be subject to rules and terms of participation imposed and administered by regional transmission operators and independent system operators, in particular MISO for our current projects. Although these entities are themselves ultimately regulated by FERC, they can impose rules, restrictions and terms of service on market participants, like our wind parks, that can have a material impact on our business. For example, independent system operators and regional transmission operators may impose bidding and scheduling rules, both to curb market power and to ensure functioning markets. The act of obtaining an Interconnect Agreement with MISO is coincident with obtaining FERC “Notice of Filing” that acknowledges the Interconnect Agreement (see Table below).

FERC rules for the establishment, approval and enforcement of Electric Reliability Standards will require each of our wind parks to register with the North American Electric Reliability Council and the regional Electric Reliability Organization. We are also required to comply with applicable Reliability Standards approved by FERC.

PUHCA and PURPA

The Public Utility Holding Company Act of 2005, or “PUHCA,” in relevant part, provides that any entity that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a “public utility company” (which is defined to include an “electric utility company”) or a company that is a “holding company” of a public utility company or public utility holding company, is subject to certain regulations granting FERC access to books and records and oversight over certain affiliate transactions. State regulatory commissions may in some instances also have access to books and records of holding companies. Entities that are holding companies solely by virtue of their ownership of “qualifying facilities” (or QF) pursuant to the Public Utility Regulatory Policies Act, or PURPA, and “exempt wholesale generators” are exempt from FERC access to books and records under PUHCA.

In order to obtain exempt wholesale generator status pursuant to PUHCA, the owner of a generating facility must demonstrate that it is engaged directly, or indirectly through one or more affiliates, and exclusively in the business of owning and/or operating facilities used exclusively for the generation of electricity for sale at wholesale.

In order to obtain qualifying facility status, a generating facility must qualify as a small power production facility or cogeneration facility that has either filed a self-certification of qualifying facility status with, or has received a qualifying facility certification order from, FERC. A wind generation facility may qualify as small power production qualifying facility if it is less than 80 MW. Certain QFs, including renewable energy facilities with a generating capacity of 30 MW or less, are exempt from certain provisions of the FPA, including the accounting and reporting requirements, and mergers and acquisitions oversight, facility disposition regulations and several other provisions of the FPA. Additionally, renewable energy facilities with a generating capacity of 30 MW or less are exempt from FERC’s ratemaking authority under the FPA. A QF has the right to require an electric utility to interconnect it to the utility’s electric system, and to purchase firm power service, back-up power and supplementary power from that interconnected electric utility at reasonable and non-discriminatory rates. Finally, a QF is exempt from the laws of the states, which otherwise regulate the ownership, rates and terms of sales, corporate governance and financing of electric utilities.

We intend that each of our wind parks will file a self-certification with the FERC that it is an exempt wholesale generator. As a result, under current federal law, we would not be subject to regulation as a holding company under PUHCA and would not be subject to this regulation as long as each “public utility company” in which we have an interest is (i) a QF, (ii) an exempt wholesale generator (“EWG”) or (iii) subject to another exemption or waiver. However, there can be no assurance that applicable law will not change.

State Regulation

Some of our wind parks will be subject to varying degrees of regulation by state public utility commissions. State public utility commissions have historically had broad authority to regulate both the rates charged by, and the financial activities of, electric utilities that sell electricity at retail, and a number of other matters relating to electric utilities, as described below. State laws may also impose certain regulatory and reporting requirements on other owners and operators of generation facilities. Independent power producers are considered to be public utilities in some states and are subject to varying degrees of regulation by state public utility commissions, ranging from a requirement to obtain a “certificate of public convenience and necessity” in order to construct and operate a generating facility, to regulation of organizational, accounting, financial and other corporate matters. While FERC has exclusive jurisdiction over the rates for wholesale sales of electric energy, states may assert jurisdiction over the location and construction of electric generating facilities, and in certain situations, over the issuance of securities and the sale or other transfer of assets by these facilities.

County Regulation

All projects in our development pipeline will, before construction can begin, require approval from the zoning boards of the relevant county governments in which the parks are located. When appropriate in the development timeline (i.e., before construction is to begin), we obtain the necessary zoning/conditional use permits (see Table below).

Historical Societies

Permits or licenses are not required for construction of wind parks, but if items of archaeological interest are discovered during construction, then there is a risk of delays or outright stoppages while the findings are investigated. To reduce or eliminate the risk of such findings, it is appropriate to conduct literature searches regarding the history of the specific sites under development. Crownbutte makes it a practice to conduct such literature surveys and to obtain letters certifying that such due diligence had been conducted (see Table below).

Federal Aviation Administration and North Dakota Aeronautics Commission

This regulatory dimension focuses on the potential safety-related impact of wind park development on regional and local air traffic, whether commercial, military, or private, regarding the projected siting of wind parks in relation to their proximity to airports and air traffic corridors. Based on the latitude and longitude of each park, the FAA or NDAC may make a “Determination of No Hazard” on flight paths for wind towers erected at that location. Crownbutte endeavors to secure such letters for all of its sites (see Table below).

Environmental Regulation

Our wind park development activities are not at this time subject to specific environmental laws or regulations in the State of North Dakota, including environmental impact review requirements and regulations governing the discharge of fill materials into protected wetlands. Occasionally, letters certifying “no impact” may be obtained as a show of good faith on the part of developers that appropriate due diligence was performed at the time of site selection (see Table below). Where possible, Crownbutte seeks to obtain such letters to certify “no impact.” However, there can be no assurances that there will not be new regulations passed in the future. In the State of New York, for example, the State Environmental Quality Review Act requires a wind developer to evaluate the potential environmental impacts caused by wind parks, including assessments of visual and noise impacts, effects on wildlife (primarily birds and bats) and impacts to historical and cultural resources, and to implement measures to mitigate those impacts to the extent practicable.

Local laws may in the future also regulate other aspects of our wind park development and operation, by setting limits on the use of local roads, setback requirements and noise standards. If we fail to comply with these possible future requirements, or with other regulatory standards, we may be denied permits that are required for construction or operation or become subject to regulatory enforcement actions. Project opponents frequently use environmental impact review statutes as a basis for mounting legal challenges to the issuance of permits and approvals. Legal challenges or enforcement actions, even if ultimately defeated, can result in substantial delays in the completion of a wind park and may have a material adverse effect on our business, results of operations and financial condition.

Our wind parks are designed to have minimal operational impact on the environment. Operation of a wind park does not produce significant wastes, generate air emissions or result in wastewater discharges. While most environmental regulatory obligations arise during or prior to the construction stage for some wind parks, significant environmental obligations may still exist even after construction is complete. For example, wind parks in New York are obligated to monitor impacts on avian species and to adopt mitigating measures if we detect substantial impacts. In most cases, the precise nature of this potential mitigation is not specified in the wind parks’ permits. While we do not currently anticipate that such regulation will be adopted in the State of North Dakota, we cannot offer any assurance that they will not, or that the mitigation will not have an adverse effect on our business, results of operations or financial condition.

LETTERS OF ”NO HAZARD” or ”NO IMPACT”

Project

County

State

Zoning/

Cond Use

FERC Notice of

Filing

FAA/ NDAC

State Hist Society

State Game &

Fish

Fed. Fish &

Wildlife

Gascoyne I

Bowman

Complete

Gascoyne II

Bowman/Adams

Not yet applied

Pending

New England

Hettinger

Not yet applied

Pending

Complete

Pending

Elgin

Grant

Complete

Not yet applied

Complete

Wibaux

n/a

Not yet applied

Pending

n/a

Pending

Berthold

Ward

Not yet applied

Pending

Complete

Pending

Carson

Grant

Not yet applied

Pending

Complete

Pending

Monarch

Fallon

n/a

Not yet applied

Pending

n/a

Pending

Tappen

Kidder

Not yet applied

Pending

Complete

Pending

Mobridge

Campbell

Not yet applied

Pending

Not yet applied

Pending

Scobey

Daniels

Not yet applied

Pending

Not yet applied

Pending

Big Sandy

Chouteau

Not yet applied

Pending

Not yet applied

Pending

Competition

In the United States, large utility companies dominate the energy production industry and coal continues to be the primary resource for electricity production. Electricity generated from wind energy faces competition from other traditional resources such as nuclear, oil and natural gas. The advantages of conventional production of electricity are that:

the technology and infrastructure already exist for the use of fossil fuels such as coal, oil and natural gas,

commonly-used fossil fuels in liquid form such as light crude oil, gasoline and liquefied petroleum gas are easy to distribute, and

petroleum energy density (an important element in land and air transportation fuel tanks) in terms of volume (cubic space) and mass (weight) is superior to some alternative energy sources.

However, energy produced by conventional resources also faces a number of challenges including:

dependence on fossil fuels from volatile regions or countries of the world creates energy security risks for dependent countries,

the inefficient atmospheric combustion (burning) of fossil fuels leads to the release of pollution into the atmosphere including carbon dioxide which is largely considered the primary cause of global warming,

extraction of fossil fuels is becoming more expensive and more dangerous as readily-available resources are exhausted and mines get deeper and oil rigs must drill deeper and further out in oceans, and

fossil fuels are non-renewable, unsustainable resources which will eventually decline in production and become exhausted resulting in a major impact on the societies that utilize these technologies.

In contrast, electricity generated from wind energy:

produces no water or air pollution that can contaminate the environment because there are no chemical processes involved in wind power generation; therefore, there are no waste by-products such as carbon dioxide,

does not contribute to global warming because it does not generate greenhouse gases, and

is a renewable source of energy which means that energy source will never be depleted.

However, wind energy producers also face certain obstacles including:

the reality that wind is unpredictable in the short run and, therefore, wind power is not predictably available, and when the wind speed decreases, less electricity is generated,

residents in communities where wind farms exist may consider them an “eyesore” and

wind farms, depending on the location and type of turbine, may negatively affect bird migration patterns and may pose a danger to the birds themselves; however, newer, larger wind turbines have slower moving blades which seem to be visible to most birds.

We expect that primary competition for the wind power industry will continue to come from utility company producers of electricity generated from coal and other non-renewable energy sources.

Within the U.S. wind power market itself, there is also a high degree of competition, with growth opportunities in all sectors of the industry regularly attracting new entrants. For example, in 2007, over 15 utility-scale wind turbine manufacturers were selling turbines in the United States market, up from only six in 2005.

Non-utility entrants in the wind power development market, however, face certain barriers to entry. The capital costs of buying and maintaining turbines are high. Other significant factors include the cost of land acquisition, the availability of transmission lines and the cost to tie into those lines, land use considerations and the environmental impact of construction and operations. Finally, another critical barrier to entry into the wind power development business is the necessary experience required to bring project to the point where they are able to secure interconnection agreements, power purchase agreements and project financing for construction.

We are aware of several other companies that are working to develop medium size wind energy projects and which management views as being competitive with certain aspects of our Company. They are:

Nacel Energy - A community wind development company founded in 2006 and focused on developing community wind projects in Wyoming, Texas and Kansas.

Wind Energy America - This company is located in and focused on wind power in Minnesota and is currently employing a strategy where it purchases rights to current or developing wind projects.

Juhl Wind - A wind energy developer focused developing medium to large-scale wind farms jointly owned by local communities, farm owners and the developer. It has a number of projects currently operating with additional projects in development.

However, none of these companies is currently directly competing with us in the geographic areas in which we are active. There are many other private wind energy companies active in our region, but it is our belief that our most significant competitors will be the utilities themselves. As the relative advantages or disadvantages of wind over fossil fuel-based generation play out, and unfolding carbon legislation emerges, utilities themselves will likely elect to develop wind farm assets themselves. The advantages that utilities have in this regard are both deep financial pockets, ownership of the transmission infrastructure, and a mechanism to sell to the end customer directly without the need for a merchant market. Montana-Dakota Utility, Basin Electric Power Cooperative, and Florida Power & Light (NextEra) have all constructed, purchased, or are in the process of developing wind energy in the North Dakota and surrounding areas.

Our Competitive Advantages

We believe that we have a number of competitive advantages in the wind energy production industry; one of our key advantages is that we try to develop projects that fit into the existing transmission system. By focusing on projects that fit, we decrease the likelihood of major transmission upgrade costs and therefore increase the percentage of successful projects. Generally projects that will fit into the transmission grid are medium-size projects which take up less land, and therefore the turbines are sited in a more ideal wind regime. We believe that our projects will generally receive better production per turbine than larger projects that need to make the project fit on the available land and, as a result, must site their turbines in less than ideal locations. Also, because we focus on projects that fit into the transmission grid, we believe we will be able to avoid curtailment issues that larger projects and regions with greater wind development often face.

We believe our management’s understanding of deregulated energy markets enables us to maximize the value of our development portfolio. Our team has experience in site selection, market analysis, land acquisition, community relations, permitting, financing, regulation and construction.

For wind energy projects to be completed successfully, projects must be constructed in a cost-effective manner. In the course of completing our project developed for, and sold turnkey to, a utility (Chamberlain, SD), we have been able to demonstrate that we can build wind farms on a cost-effective basis.

Employees

We employ approximately five full-time employees. We do not have any collective bargaining agreements with our employees and consider our employee relations to be good.

Patents and Trademarks

We have no trademarks or other proprietary rights registered with the United States Patent and Trademark Office.

Seasonality

Although our operating history is limited, we do not believe our business is significantly seasonal. The prices for electricity in the relevant nodes of the MISO area have shown price increases during peak summer months, so it is possible that, after construction of our first project, we will find some seasonality to the revenues from the sale of electricity. Based on our wind reports, we do not believe that wind speed will be significantly seasonal at our project sites.

Research and Development

During the last two fiscal years, the Company engaged in the following research and development activities, as disclosed in the accompanying notes to audited consolidated financial statements (see “Note 12 – Project Development Costs and Interconnect Application Deposits”):

On May 27, 2008 the Company entered into a joint venture agreement with Westmoreland Power, Inc., a coal company, under the name of Gascoyne II Wind Project to develop, construct, manage, and operate a 200 MW wind power project in southwest North Dakota. The Company received $200,000 from Westmoreland as compensation in order to participate in the joint venture. The Company recognized sale of development rights revenues for this amount for the year ended December 31, 2008. Crownbutte is the managing party. For the years ended December 31, 2009 and 2008, the Company expensed development costs of $11,130 and $5,126, respectively, for this project.

On June 20, 2008 the Company entered into an agreement with a wind development company to purchase the rights to develop a wind park near New England, ND for $100,000. Assets purchased by the Company consist of one met tower, 3.5 years meteorological data, and a land lease cooperation agreement. For the years ended December 31, 2009 and 2008, the Company expensed development costs of $13,901 and $89,427, respectively, for this project.

On September 18, 2008 the Company entered into an agreement with a wind development company to purchase the rights to develop a 10 MW wind park near Ralls, TX for $1,500,000. The agreement calls for a non-refundable down payment of $200,000, another payment of $1,000,000 by March 10, 2009, and a final payment of $300,000 upon beginning construction of the wind park, but no later than September 18, 2009. Assets purchased by the Company consist of meteorological data, land lease option agreements, permits, licenses, assignable interconnect agreement, right-of-ways to substations and power lines, and FFA determination. Should the Company default on any payments, the seller would be entitled to take back the assets purchased by the Company. As of December 31, 2008, the Company expensed development costs totaling $210,270 for this project.

As of December 31, 2008, the Company abandoned the Ralls, TX project forfeiting the development rights and related assets. All assets were expensed as research and development costs and were included in the $210,270 expensed as of December 31, 2008. No additional costs were incurred in 2009.

In 2007, the Company sold project development rights for a 20 MW wind park near Gascoyne, ND to a wind energy company. The Company recognized $75,000 revenue in 2006 for preliminary development work completed and earned in 2006. For the year ended December 31, 2007, additional revenue of $250,000 for sale of project development rights was earned and recognized for final development work completed prior to transfer of ownership. In 2008, the Company decided to repurchase the project. On September 30, 2008, the Company entered into an agreement with the wind development company to repurchase the development rights for the 20 MW Gascoyne, ND wind park for $325,000. For the years ended December 31, 2009 and 2008, the Company expensed development costs totaling $93,667 and $333,476, respectively, for this project as it has not yet deemed the project probable of being technically, commercially, and financially viable.

For the years ended December 31, 2009 and 2008 the Company expensed an additional $38,178 and $282,799, respectively, in development costs for smaller projects not listed above.

Financial Statements and “Going Concern” Opinion

The auditor’s report accompanying our audited financial statements for the years ended December 31, 2009 and 2008, included in this Annual Report, contained an explanation that our financial statements were prepared assuming that we will continue as a going concern. The report cites operating losses, negative cash flows from operating activities, and working capital and accumulated deficits. Our ability to continue operating as a going concern will depend on the sale of one or more greenfield projects, obtaining additional financing to develop the properties, the realization of profits through future production or sale of properties, and/or our ability to derive sufficient funds from sales of equity and/or debt securities and, thereafter, to generate sufficient funds to allow us to effectuate our business plan. We cannot provide any assurance that we will have sufficient sales or that sufficient financing will be available to us on terms or at times that we may require. Failure in any of these efforts may materially and adversely affect our ability to continue our operations.

ITEM 1A.

RISK FACTORS

This Annual Report on Form 10-K contains certain forward-looking statements. You are cautioned that such statements are only predictions and are subject to various risks and uncertainties, many of which are beyond our control, and that actual events or results may differ materially. In evaluating such statements, you should specifically consider the various factors identified in this Annual Report on Form 10-K, including the matters set forth below, which could cause actual results to differ materially from those indicated by such forward-looking statements. If any of the following risks actually occurs, our business, prospects, financial condition and results of operations could be materially adversely affected. In that case, the trading price of our common stock would likely decline and you may lose all or a part of your investment.

Risks Related to Our Business and the Wind Energy Industry

We have limited experience in completing development of wind parks and no operating history as an owner-operator of wind parks.

To date, we have developed and sold only two wind parks. We plan to continue to sell developments as a part of our ongoing business, but we intend to shift the focus of our business towards ownership and operation of merchant wind parks that we develop. We have no history as an owner-operator of wind parks from which you can evaluate our business plan, and our past performance cannot be taken as indicative of future results, especially as we change our business strategy. As we transition from being only a developer to being a developer-owner-operator of wind energy projects, our success will depend on our ability to take on those additional roles and to manage the challenges that the growth of our business will entail. Our organization has to date consisted of a small number of employees. We will be required to commence and manage significant operations, to manage growth in personnel and operations and to manage our costs as we expand our business. Our failure or inability to meet these challenges could have a material adverse effect on our business, financial condition and results of operations.

The growth of our business depends upon our ability to convert our pipeline of projects under development into operating projects.

We currently do not own or operate any wind parks (and therefore have no megawatts of capacity in operation). We may not be successful in completing our pipeline of development projects as anticipated or at all. Our portfolio of wind energy projects includes approximately 638 megawatts of capacity in various stages of development. (See “Item 1. Business.”) We expect to start construction on three 20 megawatt projects in 2010 and 2011. Our goal is to have approximately 20 megawatts of owned operating capacity by the end of 2010, and we target the construction and commissioning of approximately 40 megawatts in 2011. However, there can be no assurance we will achieve these goals.

The development and construction of wind energy projects involves numerous risks and uncertainties, including:

●

access to liquid independent systems operator markets or negotiation of power purchase agreements,

●

availability of transmission lines with adequate capacity,

●

obtaining necessary land rights,

●

turbine procurement,

●

availability of turbine, construction and permanent financing,

●

obtaining necessary governmental and regulatory approvals and permits, and

●

negative public or community response,

many of which are subject to intense competition and all of which may be beyond our control. We discuss each of these risks in additional detail below. These risks and uncertainties may prevent projects from progressing to construction and may cause us to fail to meet the targets of our development plan.

We may be unable to secure the project financing required to construct the projects currently in our portfolio.

If we fail to secure the project financing required for construction of these wind parks ($1.8-$2 million per megawatt of generating capacity), then Crownbutte will be relegated to being a green-field developer of prospective wind farm sites, whose income options will be limited to selling the development rights for those sites to entities that are capable of assembling the project financing required to construct, own, and operate wind farms. In such a case, Crownbutte’s financial position and prospects for income would be significantly impaired. The possibility of our failure to secure project finance therefore makes investment into Crownbutte risky.

We may elect not to proceed with projects currently in our portfolio.

We may elect not to proceed with projects currently in our portfolio. Our current portfolio of approximately 638 megawatts in development (we have no megawatts in operation) does not include projects representing 30 megawatts of prospective capacity that we have, since 2000, actively developed and then elected not to pursue. To date costs incurred with respect to projects we have elected not to pursue have been minimal, but this may not always be the case.

Our revenues may be inconsistent, creating a liquidity risk.

Until we make the transition to owner/operator, our revenues depend on making a small number (one to two transactions per year) of sales of the development rights to parks in our pipeline. The negotiation and lead-time to completing such transactions are not easily predictable, and may not occur at the prices or on the timing we desire. Revenues therefore can be zero for extended periods, which can result in significant liquidity risk for the company.

Development of our projects depends on access to liquid independent systems operator markets.

We do not plan to enter into power purchase agreements unless they are offered on favorable terms. Our business model focuses on the development of merchant parks, which sell electricity into a power spot market. There are several systems that provide real time and day-ahead spot markets for electricity such as Midwest Independent Transmission System Operator, PJM, Electric Reliability Council of Texas and California Independent System Operator. Our portfolio of projects is located predominately in the Midwest, and therefore our merchant projects would sell into the Midwest Independent Transmission System Operator’s spot market.

It is possible that the Midwest Independent Transmission System Operator spot market becomes illiquid due to withdrawal of its member system owners, problems in the physical transmission infrastructure, or fundamental changes in the supply or demand of electricity. In the event that the spot market no longer functions efficiently, any income streams from the sale of electricity would have a material adverse effect on Crownbutte’s financial condition and operations.

We will depend on the availability of transmission lines with adequate capacity.

We expect to generally depend on electric transmission lines owned and operated by third parties to deliver the electricity we will sell. Some of our wind energy projects in development may have limited access to interconnection and transmission capacity. The Midwest Independent Transmission System Operator will inform Crownbutte in such cases during the feasibility studies and systems impact studies that are part of the interconnection agreement process. We may not be able to secure access to the limited available interconnection or transmission capacity at reasonable systems upgrade cost, or at all. Since this interconnection agreement must be in place before any construction or turbine costs are incurred, this is a moderate financial risk for Crownbutte.

However, in the event of a failure in the transmission facilities after a project is completed, we may experience lost revenues. In addition, transmission limitations may cause us to curtail our production of electricity, impairing our ability to fully capitalize on the particular wind energy project’s potential. Any such failure could have a material adverse effect on our business, financial condition or results of operations.

The growth of our business depends on locating and obtaining control of suitable operating sites.

Wind energy projects require wind conditions that are found in limited geographic areas and particular sites. Further, wind energy projects must be interconnected to electricity transmission or distribution networks in order to deliver electricity. Once we have identified a suitable operating site, our ability to obtain requisite land control or other land rights (including access rights, setback and/or other easements) with respect to the site is subject to growing competition from other wind energy producers that have sufficient financial capacity to research, locate and obtain control of such sites and to obtain required electrical interconnection rights. Our competitors may impede our development efforts by acquiring control of all or a portion of a project site we desire to develop or obtaining a right to use land necessary to connect a project site to a transmission or distribution network. If a competitor obtains land rights critical to our project development efforts, we could incur losses as a result of stranded development costs. If we succeed in securing the property rights necessary to construct and interconnect our projects, such property rights must be insurable and otherwise satisfactory to our financing counterparties. Obtaining adequate property rights may delay development of a project, or may not be feasible. Any failure to obtain insurable property rights that are satisfactory to our financing counterparties would preclude our ability to obtain third-party financing and could prevent ongoing development and construction of the relevant projects.

Our wind energy projects’ use and enjoyment of real property rights obtained from third parties may be adversely affected by the rights of lien holders and lease holders whose rights are superior to those of the grantors of these real property rights.

Each of our wind energy projects is or will be located on land occupied pursuant to various easements and leases. Our rights pursuant to these easements and leases allow us to install wind turbines, related equipment and transmission lines for the projects and to operate the projects. The ownership interests in the land subject to these easements and leases may be subject to mortgages securing loans or other liens (such as tax liens) and other easement and lease rights of third parties (such as leases of oil, gas, coal or other mineral rights) that were created prior to our easements and leases. As a result, our rights under these easements or leases may be subject and subordinate to the rights of such third parties.

A default by a landowner at one or more of our wind energy projects under a mortgage could result in foreclosure of the landowner’s property and thereby terminate our easements and leases required to operate the projects. Similarly, it is possible that another lien holder, such as a government authority with a tax lien, could foreclose upon a parcel and take ownership and possession of the portion of the project located on that parcel. In addition, the rights of a third party pursuant to a superior lease could result in damage to or disturbance of the equipment at a project, or require relocation of project assets.

If any of our wind energy projects were to suffer the loss of all or a portion of its wind turbines or related equipment as a result of a foreclosure by a mortgagee or other lien holder of a land parcel, or damage arising from the conduct of superior lease holders, our operations and revenues could be adversely affected.

Development of wind projects is dependent on the availability of turbines and turbine financings.

Wind energy projects require delivery and assembly of turbines. The prices of turbines and electrical and other equipment have increased in recent years and may continue to increase as the demand for such equipment increases more rapidly than supply, or if the prices of key components and raw materials used to build the equipment increase. We may encounter supply and/or logistical issues in securing turbines due to the limited number of turbine suppliers and current high demand for turbines. While we have received quotes from turbine suppliers and have seen some evidence of softening turbine prices and shorter delivery lead times as the financial market turmoil during the autumn of 2008 has slowed the installation of new wind capacity, we currently have no turbines under contract but expect to have a turbine supply agreement by May 2010. We may not be able to purchase a sufficient quantity of turbines from suppliers, and suppliers may give priority to other customers. Turbine suppliers may delay the performance of or be unable to meet contractual commitments, or components and equipment may be unavailable, which would have a material adverse effect on our business, financial condition and results of operations.

In addition, we expect to require third-party turbine supply loans or other financing for our turbine purchases, which account for the majority of the total cost of a wind energy project. An inability to obtain such financing on attractive terms in the future may preclude us from obtaining additional turbines, severely limiting our growth. Moreover, a significant increase in the cost of obtaining such financing could have a material adverse effect on the investment returns we achieve from our projects.

In addition, spare parts for wind turbines and key pieces of electrical equipment may be unavailable to us. If we were to experience a serial failure of any spare part we would incur delays in waiting for shipment of these items to the site. In addition, we do not carry spare substation main transformers. These transformers are designed specifically for each wind energy project, and the current lead time to order this equipment is up to one year. If we have to replace any of our transformers, we would be unable to sell electricity from the affected wind energy project.

When we purchase our turbines, we also enter into warranty agreements with the manufacturer. Damages payable by the manufacturer under these agreements are typically subject to an aggregate maximum cap that is a portion of the total purchase price of the turbines. Losses in excess of these caps will be our responsibility. Since our turbine warranties generally expire within a certain period of time after the turbine delivery date or the date such turbine is commissioned, we may lose all or a portion of the benefit of the warranties if we are unable to deploy turbines we have purchased upon delivery.

We will need to raise additional capital to meet our business requirements, and such capital raising may be costly or difficult to obtain and could dilute current stockholders’ ownership interests.

To date, our capital expenditures and working capital requirements have been funded by income from operations and equity capital. Our income from operations will not be sufficient to fund our business plan. We plan to raise approximately $1 million through private placements of equity by the end of 2010, the proceeds of which, together with cash on hand, will be used for general corporate expenses associated with the hiring of new staff required to accelerate our development activities, as well as move into our new owner-operator business model, which requires oversight of construction of projects, as well as the operations and maintenance of projects after construction is complete. However, we may be unable to secure this additional financing on terms acceptable to us, or at all, at times when we need such financing. These fundings do not include financing of project construction and operation. See “Our projects will entail significant capital expenditures and construction costs, and we will require additional financing to construct and operate them” below.

If we are unable to obtain such additional equity financing on a timely basis, we may have to curtail our development activities or be forced to sell assets, perhaps on unfavorable terms, which would have a material adverse effect on our business, financial condition and results of operations. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees, accounting fees, securities law compliance fees, printing and distribution expenses and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertible notes, restricted stock, stock options and warrants, which may adversely impact our financial condition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” below.

Any future issuance of our equity or equity-backed securities may dilute then-current stockholders’ ownership percentages. See “You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock” below.

Our projects will entail significant capital expenditures and construction costs, and we will require additional financing to construct and operate them.

We are in a capital intensive business, and our projects in development and construction have entailed and will entail significant capital expenditures and construction costs, and recovery of the capital investment in a wind energy project generally occurs over a lengthy period of time. The capital investment required to construct a wind energy project is primarily based on the costs of fixed assets required for the project. We will require additional financing, including tax equity financing transactions (described below), to complete the construction of and to operate our existing projects. Additional financing may not be available on acceptable terms or at all.

After we have developed a wind energy project that we intend to own to the point where we are prepared to commence construction, we would expect typically to enter into a limited recourse construction loan. Proceeds from construction loans would typically be used to retire turbine indebtedness and to pay construction costs, including costs to construct roads, substations, transmission lines and the balance of plant. Construction loans are generally secured by the project’s assets and our equity interests in the project companies. In certain instances we may enter into a construction loan for a single project, while in other instances we may be able to finance multiple projects through a single credit facility. We will also likely use equity capital contributions (our own and potentially from other investors as described above) to fund a portion of each project’s construction costs.

We would forego the need for construction loans (as well as turbine supply loans) if we are able to secure 100% debt or 100% equity-based investment for any given project. A 100% debt financing would be done on a limited recourse basis and be secured by the project assets and our equity. In a 100% equity financing, the outside equity investors would contribute all of the project costs as equity in return for an 80% to 90% share of the returns. However, while we are exploring these possibilities, these structures have not in the past been the norm in the wind generation industry and may not be available. Our proposed financing for the Gascoyne I project with 100% debt and an 80% ownership stake is a unique transaction, and we do not expect it to be the norm for financing additional parks.

Once construction of a wind energy project is completed and commercial operations commence, we will seek to finance the project on a long-term basis through a combination of term loans and tax equity financing, to the extent available. (See “We expect to be materially dependent on tax equity financing arrangements for projects financed after 2010” below.)

The unprecedented upheaval in the debt and equity markets in the U.S. and around the world in recent months has made all categories of financing more difficult to secure. See ”Management’s Discussion and Analysis of Financial Condition and Results of Operations—Project Finance.”

Our strategy of relying on a merchant park model may make project financing more difficult and may adversely affect results of operations.

Our business model focuses on the development of merchant parks. We do not plan to enter into power purchase agreements unless they are offered on favorable terms. Merchant parks sell electricity on the open market. The reliance on the merchant market (i.e., the lack of power purchase agreements) can be a significant barrier to achieving construction financing and project financing with equity investors (as described below), many of whom seek the security of long-term power purchase agreements with power off-takers.

Our efforts to secure project finance have confirmed that investment banks and other financial institutions that have brokered or directly financed wind projects in the past have a continued desire to see power purchase agreements as the off-take arrangement in place for projects they seek to represent or finance. Such a desire for a power purchase agreement on the part of financiers is natural, but may not be possible to achieve by Crownbutte. There are no federal or state mandates in place that require utilities to offer power purchase agreements in North Dakota, where the bulk of Crownbutte’s projects are located.

Crownbutte to date has not secured project financing for any of its parks in development, although we are currently in the due diligence phase for funding for the Gascoyne I project. If power purchase agreements cannot be secured, and financiers decline to fund any of Crownbutte’s merchant park model projects, there will be a significant adverse effect on Crownbutte’s finances and operations. While we anticipate closing the finance deal for Gascoyne I in the second quarter of 2010, there is no guarantee the funding will be approved.

We expect to be materially dependent on tax equity financing arrangements for projects financed after 2010.

Beyond the three projects we believe may qualify for the U.S. Treasury Department renewable energy grant program, the majority of our projects will require other types of financing. For those projects, we intend to seek tax equity financing to provide the majority of the permanent capital needs for each project we will own. The availability of tax equity financing depends on federal tax attributes that encourage renewable energy development. These attributes primarily include (i) renewable energy federal production tax credits, which are federal income tax credits related to the quantity of renewable energy produced and sold during a taxable year and (ii) accelerated depreciation of renewable energy assets as calculated under the Modified Accelerated Cost Recovery System of the Internal Revenue Code. We do not expect to generate sufficient taxable income from owned projects to use all of the production tax credits or the accelerated depreciation expected to be available to us under these programs. Although the economic downturn and financial market turmoil of 2008 lingers, the tax appetite of financial institutions may rebound sooner than anticipated, making the tax equity financing more available. Under the U.S. Treasury Department renewable energy grant program, a non-taxable cash grant equal to 30% of a project’s authorized capital costs can be received in lieu of investment tax credits or production tax credits. The U.S. Treasury Department renewable energy grant program is scheduled to expire on December 31, 2010. We believe the availability of the grant program is more attractive than tax equity financing to most investors, however, we anticipate that will change upon expiration of the grant program. As the economy recovers, institutional profits will increase and tax appetite for PTC and accelerated depreciation tax benefits will return.

In a typical tax equity financing, we would receive a capital investment in exchange for an equity interest in our subsidiary that owns the project. These equity interests entitle the investors to receive a substantial portion of the project’s cash distributions from electricity sales and related hedging agreements, production tax credits and taxable income or loss until such investors reach an agreed rate of return on their investment. As a result, a tax equity financing substantially reduces the cash distributions from the applicable projects available to us for other uses, and the period during which the tax equity investors receive cash distributions from electricity sales and related hedging agreements may last longer than expected if our wind energy projects perform below our expectations.

Moreover, there are a limited number of potential tax equity investors, they have limited funds and wind energy developers compete with other renewable energy developers and others for tax equity financing. To date, the wind industry’s tax equity investors have been large financial institutions with significant taxable income. The unprecedented upheaval in the debt and equity markets in the U.S. and around the world in recent months has resulted in lower profits for many financial institutions, making tax equity investing less available in general. Furthermore, as the renewable energy industry expands, the cost of tax equity financing may increase and there may not be sufficient tax equity financing available to meet the total demand in any year. If we are unable to enter into tax equity financing agreements with attractive pricing terms or at all, we may not be able to use the tax benefits provided by production tax credits and accelerated tax depreciation, which could have a material adverse effect on our business, financial condition and results of operations.

In addition, our tax equity financing agreements are expected to provide our tax equity investors with a number of approval rights with respect to the applicable project or projects, including approvals of annual budgets, indebtedness, incurrence of liens, sales of assets outside the ordinary course of business and litigation settlements. As a result of these restrictions, the manner in which we conduct our business may be limited. See ”Management’s Discussion and Analysis of Financial Condition and Results of Operations—Project Finance.”

The growth of our business depends upon the extension of the expiration date of the production tax credit/investment tax credit, which currently expires on December 31, 2012, and other federal and state governmental policies and standards that support renewable energy development.

We depend heavily on government policies supporting renewable energy that make the development and operation of wind energy projects economically feasible. In particular, we cannot economically develop and construct our pipeline of development projects without the federal production tax credit, which will expire on December 31, 2012, unless legislation is enacted to extend it. The production tax credit currently provides a $21 federal tax credit per megawatt hour for a renewable energy facility that uses wind, geothermal or closed-loop biomass fuel sources in each of the first ten years of its operation and applies to facilities that are placed in service before the end of 2012. These facilities will continue to benefit from the current production tax credit incentive until the end of the ten-year period from the date on which the wind turbines are placed in service. Without an extension of the expiration date of the production tax credit, wind energy projects may not be economically feasible to develop and construct.

An option to the production tax credit is the 30% investment tax credit wherein a taxpayer may claim 30% of investment amount as a tax credit in lieu of the production tax credit.

As part of the American Recovery and Reinvestment Act of 2009, a project placed in service in 2009 or 2010 may receive a cash grant from the U.S. Treasury Department in lieu of investment tax credits or production tax credits. The grant amount for most wind projects would equal to 30% of the authorized capital costs of the project. The grant does not constitute taxable income.

In addition to the production tax credit/investment tax credit, we rely on other incentives that support the sale of energy generated from renewable sources, including state adopted Renewable Portfolio Standards programs. Renewable Portfolio Standards programs often operate in tandem with a credit trading system through which generators can buy or sell Renewable Energy Certificates that are issued by the state to generators of renewable energy to meet mandated renewable requirements. At this time, North Dakota has no Renewable Portfolio Standards, and it is not anticipated that they will have Renewable Portfolio Standards in the near future. Other states including Montana and Minnesota provide a range of incentives through Renewable Portfolio Standards programs.

While federal and state governments have promoted renewable energy in the past, policies may be adversely modified or support of renewable energy development, particularly wind energy, may not continue. If governmental authorities fail to continue supporting, or reduce their support for, the development of renewable energy projects, particularly wind energy projects, it could materially adversely affect our ability to develop and construct our pipeline of development projects and grow our business.

The design, construction and operation of wind energy projects are highly regulated and the failure of being granted operating and construction permits could materially adversely affect our business, financial condition and results of operations.

The design, construction and operation of wind energy projects are highly regulated activities requiring various material governmental and regulatory approvals and permits. Procedures for the granting of operating and construction permits vary by jurisdiction and certain jurisdictions may deny requests for permits for a variety of reasons. Further, we may not be able to renew construction and operating permits when required. Failure to procure and maintain the necessary permits may prevent ongoing development, construction and continuing operation of our projects. In addition, in some circumstances we may have to commence construction prior to obtaining all required permits, which exposes us to the risk that we may subsequently be unable to secure all of the permits required to complete the project. If this were to occur, we could experience considerable losses as a result of our prior investment.

Our projects may be subject to regulation by the Federal Energy Regulatory Commission under the Federal Power Act or other regulations that regulate the sale of electricity, which may adversely affect our business.

Certain of our projects may be able to obtain qualifying facility status under the Public Utility Regulatory Policies Act, or PURPA. Qualifying facilities are exempt from certain provisions of the Federal Power Act, including the accounting and reporting requirements, and mergers and acquisitions oversight, facility disposition regulations and several other provisions of the Federal Power Act. Additionally, renewable energy facilities with a generating capacity of 30 megawatts or less are exempt from the Federal Energy Regulatory Commission’s ratemaking authority under the Federal Power Act.

Exempt wholesale generators are generation owning public utilities (including producers of renewable energy, such as wind projects) that are engaged exclusively in the business of owning and/or operating generating facilities and selling electric energy at wholesale. The owner of a renewable energy facility that has been certified as an exempt wholesale generator in accordance with the Federal Energy Regulatory Commission’s regulations is subject to the Federal Power Act and to the Federal Energy Regulatory Commission’s ratemaking jurisdiction, but the Federal Energy Regulatory Commission typically grants exempt wholesale generators the authority to charge market-based rates as long as the exempt wholesale generator can demonstrate that it does not have, or has adequately mitigated, market power and cannot otherwise erect barriers to market entry. The Federal Energy Regulatory Commission generally grants an exempt wholesale generator waivers from many of the requirements that are otherwise imposed on public utilities under the Federal Power Act.

The Public Utility Holding Company Act of 2005 in part provides that any entity that owns, controls or holds power to vote 10% or more of the outstanding voting securities of a “public utility company” (which is defined to include an “electric utility company”) or a company that is a “holding company” of a public utility company or public utility holding company, is subject to certain regulations granting the Federal Energy Regulatory Commission, access to books and records and oversight over certain affiliate transactions. State regulatory commissions may in some instances also have access to books and records of holding companies. However, entities that are holding companies solely by virtue of their ownership of qualifying facilities and exempt wholesale generators are exempt from most of the Public Utility Holding Company Act requirements.

We intend that each of our wind parks will file a self-certification with the Federal Energy Regulatory Commission that it is an exempt wholesale generator. As a result, under current federal law, we would not be subject to regulation as a holding company under Public Utility Holding Company Act and would not be subject to this regulation as long as each “public utility company” in which we have an interest is (i) a qualifying facility, (ii) an exempt wholesale generator or (iii) subject to another exemption or waiver.

Although the sale of electric energy has been to some extent deregulated, the industry is subject to increasing regulation and even the threat of re-regulation. Due to major regulatory restructuring initiatives at the federal and state levels, the U.S. electric industry has undergone substantial changes over the past several years. We cannot predict the future design of wholesale power markets or the ultimate effect ongoing regulatory changes will have on our business. Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the movement towards competitive markets. If the deregulation of the electric power markets is reversed, discontinued or delayed, our business prospects and financial results could be negatively affected. See “Business—Regulation” for more information.

Negative public or community response to wind energy projects may adversely affect our ability to construct our projects.

There has been negative public and/or community response to wind energy projects in some areas of the United States, and such factors may adversely affect our ability to construct our projects in certain areas. In addition, legal challenges may result in an injunction against construction or operation, impeding our ability to place projects in operation according to schedule, meet our development and construction targets or generate revenues. An increase in opposition to the granting of permits or unfavorable outcomes of such challenges could materially and adversely affect our development plans.

Projects that reach construction may not be completed or, if completed, may not meet our return expectations.

Those projects that do progress to construction may not be completed on a timely basis or at all or, if completed, may not meet our return expectations, due to factors such as:

●

schedule delays,

●

cost overruns,

●

failure to receive turbines or other critical components and equipment from third parties on schedule and according to design specifications

●

unsatisfactory completion of construction,

●

shortfalls of anticipated capacity factor,

●

adverse weather,

●

lower natural gas prices,

●

lower than forecast spot electricity prices, and

●

force majeure or other events out of our control.

Any of the above factors could give rise to construction delays and construction costs in excess of our budgets, which could prevent us from completing construction of a project, cause defaults under our financing transactions and impair our business, financial condition and results of operations.

In a situation where a power purchase agreement is in place, if we fail to construct a wind energy project in a timely manner or do not deliver electricity in accordance with the applicable power purchase agreement, the power purchase agreement may be terminated and/or we could be required to pay liquidated damages.

Wind energy project revenues are highly dependent on suitable wind and associated weather conditions.

The energy and revenues generated at a wind energy project are highly dependent on climatic conditions, particularly wind conditions, which are variable and difficult to predict. Turbines will only operate within certain wind speed ranges that vary by turbine model and manufacturer, and there is no assurance that the wind resource at any given project site will fall within such specifications.

When we develop a wind energy project, we evaluate the quality of the wind resources at the selected site through a number of means, and we retain third-party experts to assist us in this evaluation. We base our investment decisions with respect to each wind energy project on the findings of wind studies conducted on-site before starting construction. We use the wind data that we gather to develop projections of the wind energy project’s performance, revenue generation, operating profit, debt capacity, tax equity capacity and return on investment, which are fundamental elements of our business planning. Wind resource projections at the start of commercial operations can also have a significant impact on the amount of third-party capital that we can raise, including the expected contributions by tax equity investors. However, actual climatic conditions at a project site, particularly wind conditions, may not conform to the findings of these wind studies, and, therefore, our wind energy projects may not meet anticipated production levels, which could adversely affect our forecasted profitability. In addition, global climate change could change existing wind patterns; such effects are impossible to predict.

Inaccurate wind resource projections on the performance of one or more of our wind energy projects resulting in unfavorable projected net capacity factor levels, could materially adversely affect our business, financial condition and results of operations.

We project the net annual capacity factor for each project in our development portfolio. Net capacity factor is one element used in measuring the productivity of a wind turbine, wind energy project or any other power production facility. It compares the turbine’s production over a given period of time with the amount of power the turbine could have produced if it had run at full capacity for the same amount of time.

	Amount of power produced over time (usually measured annually)
Net Capacity Factor =
	Power that would have been produced if turbine operated at full capacity 100% of the time over the same period of time

Projections of net capacity factor depend on wind resource projections, which rely upon assumptions such as wind speeds, interference between turbines, effects of vegetation and land use and terrain effects. The amount of electricity generated by a wind energy project depends upon many factors in addition to the quality of the wind resource, including turbine performance, aerodynamic losses resulting from wear on the wind turbine, degradation of turbine components, icing and the number of times an individual turbine or entire wind energy project may need to be shut down for maintenance or to avoid damage. In addition, conditions on the electrical transmission network can affect the amount of energy we can deliver to the network. Wind energy projects in our portfolio may fail to meet our energy production expectations in any given time period. If our wind energy projections are not realized, we could face a number of material issues, including:

●

our energy sales may be significantly lower than we forecast;

●

our energy hedging arrangements may be adversely affected;

●

we may not produce sufficient energy to meet our forward Renewable Energy Certificate sales and, as a result, we may have to buy Renewable Energy Certificates on the open market to cover our position;

●

we may earn fewer production tax credits than projected, which would increase the period during which we must make certain distributions and allocations to our tax equity investors; and

●

our wind energy projects may not generate sufficient cash flow to make payments on principal and interest as they become due on our project related debt.

If, as a result of inaccurate wind resource projections, the performance of one or more of our wind energy projects falls below our projected net capacity factor levels, our business, financial condition and results of operations could be materially adversely affected.

Volatile natural gas prices may adversely impact the market price for electricity.

Natural gas is one of the major sources of energy for the generation of electricity in the U.S. The prices for natural gas have been very volatile in recent months and years, with temporary highs in June-July of 2008 that were four times the prices in January 2002. Since June, the prices for natural gas used in electricity generation have fallen back to levels seen in December 2007 and January 2008. It is not possible to reliably predict what the price behavior for natural gas will be in the future. If prices continue to fall, they will adversely impact the economics for wind power, since natural gas-based generation is one of the chief competitors to wind energy. While there can be no assurance, in the long term we expect that the continuing need to control greenhouse gas emissions, and the fact that all fossil fuels are a finite resource, will allow wind power to continue to compete favorably with natural gas.

A sustained decline in market prices for electricity may materially adversely affect our revenues and the growth of our business.

We may not be able to develop or operate our pipeline of development projects economically if there is a sustained material decline in market prices for electricity. Electricity prices are affected by various factors and may decline for many reasons that are not within our control, including changes in the cost or availability of fuel, regulation and acts of governments and regulators, changes in supply of generation capacity, changes in power transmission or fuel transportation capacity, seasonality, weather conditions and changes in demand for electricity. In addition, other power generators may develop alternative technologies to produce power, including fuel cells; clean coal and coal gasification; micro turbines; photovoltaic (solar) cells or tidal current based generators, or improve upon traditional technologies and equipment, such as more efficient gas turbines or nuclear or coal power plants with simplified and safer designs, among others. Advances in these or other technologies could cause a sustained decline in market prices for electricity. If there is a sustained decline in the market prices of electricity, we may not develop and construct our pipeline of development projects and grow our business, and/or we may not be able to operate completed projects economically, which would have a material adverse effect on our revenues.

While we will explore the viability of hedging against the possible drop of local electricity prices, in our anticipated spot market solid hedging instruments (with high correlations to the local power market price histories) may not be available, which would represent an overall risk to the success of the business model, and is a possible barrier to achieving project financing.

The continuing U.S. recession will adversely affect the price of electricity in the near term.

A sustained decline in market prices for Renewable Energy Certificates may materially adversely affect our revenues and the growth of our business.

Similarly, if there is a sustained material decline in Renewable Energy Certificates prices, we may not be able to achieve expected revenues, which would have an adverse effect on the investment returns on our projects. A Renewable Energy Certificate is a stand-alone tradable instrument representing the attributes associated with one megawatt hour of energy produced from a renewable energy source. These attributes typically include reduced air and water pollution, reduced greenhouse gas emissions and increased use of domestic energy sources. Many states use Renewable Energy Certificates to track and verify compliance with their Renewable Portfolio Standards (“RPS”) programs, which vary among states, but generally require power suppliers to provide a minimum percentage or base amount of electricity from specified renewable energy sources for a given period of time. Retail energy suppliers can meet the requirements by purchasing Renewable Energy Certificates from renewable energy generators, in addition to producing or acquiring the electricity from renewable sources.

Our hedging strategy may not adequately manage our commodity price risk, may expose us to significant losses and may limit our ability to benefit from higher electricity prices.

Our ownership and operation of wind energy projects will expose us to volatility in market prices of electricity and Renewable Energy Certificates. In an effort to stabilize our returns from electricity sales, we intend to carefully review the electricity sale options for each of our development projects. As part of this review, we will assess the appropriateness of entering into a fixed price power purchase agreement and/or a financial hedge. If we sell our electricity into a liquid independent systems operator market, we may enter into a financial hedge with institutional investors in order to stabilize our projected revenue stream.

Under the terms of our anticipated financial hedges, we would not be obligated to physically deliver or purchase electricity, but we would receive payments for certain quantities of electricity based on a fixed price and would be obligated to pay the market electricity price for the same quantities of electricity. Thus, if market prices of electricity increase, we are obligated to make payments under these financial hedges. Our financial hedges will cover quantities of electricity that we estimate we can produce with a high degree of certainty. As a result, gains or losses under the financial hedges should be offset by decreases or increases in our revenues from spot sales of electricity in liquid independent systems operator markets. However, the actual amount of electricity we generate from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions, catastrophic events such as fires, earthquakes, storms and changes in weather patterns due to climate change. To the extent actual amounts produced fall short of the quantities covered in our financial hedges, we will not be hedged and we will be exposed to commodity price risk. In the event a project does not generate the amount of electricity covered by the related hedge, we could incur significant losses under the financial hedge if electricity prices rise substantially above the fixed prices provided for in the hedge. If a project generates more electricity than is covered by the relevant hedge, the excess production will not be hedged and the revenues we derive will be subject to market price fluctuations.

We may seek to sell forward a portion of our Renewable Energy Certificates in an effort to hedge against future declines in Renewable Energy Certificate prices. If our projects are unable to generate the amount of electricity required to earn the Renewable Energy Certificates sold forward or if we are unable for any reason to qualify our electricity for Renewable Energy Certificates in relevant states, we may incur significant losses.

We may be required to post cash collateral and issue letters of credit for obligations under hedging arrangements, which may not be available on acceptable terms and if available would reduce our capacity to borrow for other purposes. Our inability to effectively manage market risks and our hedging activities may have a material adverse effect on our business, financial condition or results of operations. In addition, our hedging activities may also limit our ability to realize the full benefit of increases in electricity prices and Renewable Energy Certificates. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Hedging.”

We will be dependent upon the continued and uninterrupted operation of a limited number of operating wind parks in a limited geographic area.

We intend to shift the focus of our business towards ownership and operation of merchant wind parks, but we currently have no owned wind energy projects in operation, and we anticipate having only a limited number of wind parks in operation over the next two years. As a result, in future our operations may be subject to material interruption if any of our wind parks is damaged or otherwise adversely affected by one or more accidents, severe weather or other natural disasters. Tornados, lightning strikes, floods, severe storms, wildfires or other exceptional weather conditions or natural disasters could damage our wind energy projects and related facilities and decrease production levels. These events could have a material adverse effect on our revenues, particularly to the extent that they affect multiple wind energy projects and project sites. In addition, a majority of our planned wind parks will be located in the three-state region of North Dakota, South Dakota and Montana. If any of our future operating wind parks experiences material interruptions or if the regulatory environment or energy market characteristics in these states were to change in a manner adverse to us, it could have an adverse effect on our business, results of operations and financial condition.

Factors beyond our control could cause us to experience increased costs with respect to our wind energy projects.

Factors such as:

●

increases in the costs of labor or materials,

●

higher than anticipated financing costs for our wind energy projects,

●

non-performance by third-party suppliers or subcontractors,

●

turbine breakdowns,

●

electricity network and other utility service failures, and

●

major incidents and/or catastrophic events, such as fires, earthquakes or storms,

may cause us to experience increased costs with respect to our wind energy projects and have a material adverse effect on our business, financial condition and results of operations.

The cost of repairing or replacing damaged equipment may be considerable, and repeated or prolonged interruption may result in termination of contracts, litigation and substantial damages or penalties for regulatory or contractual non-compliance, reduced cash flows and increased financing costs. Moreover, these amounts may not be recoverable under insurance policies or contractual claims and, in relation to network failures, network service providers and market operators may also benefit from contractual limitations of liability, which would reduce any recovery of damages from them.

In addition, our wind turbines and associated equipment will also require routine maintenance in order to continue to function properly. If the level of maintenance and capital expenditure exceeds our projected or contracted level, the cash flow available from the projects will be reduced, which may have an adverse impact on our results of operations and financial condition.

Our key suppliers may experience technical issues with their wind turbine technology.

Wind turbine technology is constantly changing and improving, and it is possible that turbine types installed by us may become obsolete. In addition, as turbine manufacturers expand or are purchased by another company, support of existing turbine models may cease. Supplier-related deficiencies may result in a prolonged shutdown of a number of turbines. In addition, a failure of performance may adversely affect our ability to arrange and close turbine supply loans, tax equity financing transactions or construction loans involving turbines. Moreover, turbine suppliers may not be able to fund the obligations they may owe us or their other customers under outstanding warranty agreements.

We expect to rely on a limited number of key customers.

We do not plan to enter into power purchase agreements unless they are offered on favorable terms. However, to the extent we do enter into power purchase agreements, we expect to depend on sales of electricity under those power purchase agreements to a limited number of utilities. We also expect to depend on sales of Renewable Energy Certificates to certain key customers and on electricity marketing agreements with a limited number of system owners and power marketing firms. Our operations will be highly dependent upon such customers’ and marketers’ fulfilling their contractual obligations under their agreements with us. Our customers may not comply with their contractual payment obligations or may become subject to insolvency or liquidation proceedings during the term of the relevant contracts, and the credit support received from such customers may not be sufficient to cover our losses in the event of a failure to perform. An inability or failure by such customers to meet their contractual commitments or insolvency or liquidation of our customers could have a material adverse effect on our business, financial position and results of operations.

We will use utilities or power marketing firms to dispatch electricity from any projects that do not have a power purchase agreement. These firms will act as an intermediary between us and system operators, such as Midwest Independent Transmission System Operator, who act as market makers for electricity pricing. The failure or inability of these firms to properly sell our electricity into the open market may lead to lower than expected project revenues.

Our development activities and operations are subject to environmental regulation and risks from environmental hazards.

We are subject to various safety, environmental and natural resource protection laws and regulations in each of the jurisdictions in which we operate. These laws and regulations require us to obtain and maintain permits and approvals, undergo environmental review processes and implement required environmental, health and safety programs and procedures to control risks associated with the siting, construction, operation and decommissioning of wind energy projects. We cannot predict whether all permits required for a given project will be granted, whether the conditions associated with such permits will be achievable or whether such permits will be the subject of significant opposition. The denial of a permit essential to a project or the imposition of conditions with which it is not practicable or feasible to comply could impair or prevent our ability to develop a project. Significant opposition and delay in the environmental review and permitting process also could impair or delay our ability to develop a project.

If we fail to comply with our permits, we may be required to pay fines or curtail production at our facilities. Violations of environmental laws in certain jurisdictions, including with respect to certain violations of laws protecting migratory birds and endangered species, may also result in criminal penalties.

We have incurred and will continue to incur capital and operating expenditures and other costs in the ordinary course of business in complying with safety and environmental laws and regulations in the jurisdictions in which we operate. In addition, we may incur costs outside of the ordinary course of business to compensate for any environmental harm caused by our facilities, which may have a material adverse effect on our business, financial condition and results of operations.

Operation of wind parks may expose us to liability for injury to persons or property.

The nature of wind turbines as large rotating machinery, as well as the presence of high voltage electrical systems, may result in personal injury and loss of life and severe damage to or destruction of property and equipment, which could result in suspension or termination of operations as well as the imposition of civil or criminal penalties.

We are not able to insure against all potential risks and may become subject to higher insurance premiums.

In addition to potential liability for injury to persons or property, our business is exposed to many other risks inherent in the construction and operation of wind energy projects, such as breakdowns, manufacturing defects, natural disasters, terrorist attacks and sabotage. We are also exposed to environmental risks. We believe we will be able to obtain insurance with respect to our proposed activities as an owner-operator of wind parks with coverages and limits customary for similarly situated businesses, but there can be no assurance that such insurance will be or will remain available at rates that are economic or at all. Failure to obtain insurance may hinder or prohibit our ability to secure project financing. Our existing insurance policies cover, and we would expect future policies to cover, losses as a result of force majeure, and natural disasters, but not terrorist attacks and sabotage. In addition, our insurance policies are and will be subject to annual review by our insurers, and these policies may not be renewed at all or on similar or favorable terms. If we were to incur a serious uninsured loss or a loss significantly exceeding the limits of our insurance policies, the results could have a material adverse effect on our business, financial condition and results of operations.

The loss of one or more members of our senior management or key employees may adversely affect our ability to implement our strategy.

We depend on our skilled and experienced management team, including Timothy H. Simons, our Chief Executive Officer. We would be materially adversely affected in the event that the services of Mr. Simons or other management or key personnel for any reason ceased to be available and adequate replacement personnel were not found. We have not obtained key-man insurance on the life of Mr. Simons. Such insurance may not be available in the future on terms acceptable to us, and there can be no assurance we will be able to secure such insurance. We also depend on our ability to attract qualified new employees in order to meet our business objectives. If we lose a member of the management team or a key employee, we may not be able to replace him or her. Integrating new employees into our management team could prove disruptive to our daily operations, require a disproportionate amount of resources and management attention and ultimately prove unsuccessful. An inability to attract and retain sufficient technical and managerial personnel could limit or delay our development efforts, which could have a material adverse effect on our business, financial condition and results of operations.

Technological changes in the energy industry could render existing wind energy projects and technologies uncompetitive or obsolete.

The energy industry, and especially the renewable energy industry, is rapidly evolving and is highly competitive. Technological advances may result in lower costs for sources of energy, and may render existing wind energy projects and technologies uncompetitive or obsolete. Wind parks have a long life (generally about 20 years), and cannot easily, or without substantial expense, be upgraded to new turbine technology. Our inability or failure to adopt new technologies as they are developed could have a material adverse affect our business, financial condition and results of operations.

Factors over which we have little or no control may cause our operating results to vary widely from period to period, which may cause our stock price to decline.

Our operating results may fluctuate significantly from period-to-period depending on several factors, including varying weather conditions; changes in regulated or market electricity prices; electricity demand, which follows broad seasonal demand patterns; changes in market prices for Renewable Energy Certificates; marking to market of our hedging arrangements and unanticipated development or construction delays. Thus, a period-to-period comparison of our operating results may not reflect long-term trends in our business and may not prove to be a relevant indicator of future earnings. These factors may harm our business, financial condition and results of operations and may cause our stock price to decline.

Current or future litigation or administrative proceedings could have a material adverse effect on our business, financial condition and results of operations.

Various individuals and interest groups may sue to challenge the issuance of a permit for a wind energy project or seek to enjoin construction of a wind energy project. The costs related to investigation, as well as our own internal investigation, could be significant. Unfavorable outcomes or developments relating to hypothetical proceedings or investigations, such as judgments for monetary damages and other remedies, including injunctions or revocation of permits, could have a material adverse effect on our financing plans, business, financial condition and results of operations, and we could settle claims that could adversely affect our financial position and results of operations.

Requirements associated with being a public company will increase our costs significantly, as well as divert significant company resources and management attention, which could negatively impact our results of operations and/or distract management from the business of project development and financing.

As a reporting company under U.S. securities laws, and we will be obliged to comply with the provisions of applicable U.S. laws and regulations, including the Securities Act of 1933, as amended (the “Securities Act”), the Securities Exchange Act of 1934 (the “Exchange Act”) and the Sarbanes-Oxley Act of 2002 and the related rules of the Securities and Exchange Commission, and the rules and regulations of the relevant U.S. market. We are working with our legal, independent accounting and financial advisors to identify those areas in which changes should be made to our financial and management control systems to manage our growth and fulfill our obligations as a public company. These areas include corporate governance, corporate control, internal audit, disclosure controls and procedures, financial reporting and accounting systems. We have made, and will continue to make, changes in these and other areas. Preparing and filing annual and quarterly reports and other information with the Securities and Exchange Commission, furnishing audited reports to stockholders and other compliance with these rules and regulations will involve a material increase in regulatory, legal and accounting expenses and the time and attention of management, and there can be no assurance that we will be able to comply with the applicable regulations in a timely manner, if at all.

In addition, being a public company could make it more difficult or more costly for us to obtain certain types of insurance, including directors’ and officers’ liability insurance, and we may be forced to accept reduced policy limits and coverage or incur substantially higher costs to obtain the same or similar coverage.

Applicable regulatory requirements, including those contained in and issued under the Sarbanes-Oxley Act, may make it difficult for us to retain or attract qualified officers and directors, which could adversely affect the management of our business and our ability to obtain or retain listing of our common stock.

We may be unable to attract and retain those qualified officers, directors and members of board committees required to provide for effective management because of the rules and regulations that govern publicly held companies, including, but not limited to, certifications by principal executive and financial officers. The enactment of the Sarbanes-Oxley Act has resulted in the issuance of a series of rules and regulations and the strengthening of existing rules and regulations by the Securities and Exchange Commission, as well as the adoption of new and more stringent rules by the stock exchanges. The perceived increased personal risk associated with these changes may deter qualified individuals from accepting roles as directors and executive officers.

Further, some of these changes heighten the requirements for board or committee membership, particularly with respect to an individual’s independence from the corporation and level of experience in finance and accounting matters. We may have difficulty attracting and retaining directors with the requisite qualifications. If we are unable to attract and retain qualified officers and directors, the management of our business and our ability to obtain or retain listing of our common stock on any stock exchange (assuming we elect to seek and are successful in obtaining such listing) could be adversely affected.

Risks Related to Our Securities

There is not now, and there may not ever be, an active market for our common stock.

There currently is a limited public market for our common stock. Further, although our common stock is currently quoted on the OTC Bulletin Board (the “OTCBB”), trading of our common stock may be extremely sporadic. For example, several days may pass before any shares may be traded. As a result, an investor may find it difficult to dispose of, or to obtain accurate quotations of the price of, the common stock. There can be no assurance that a more active market for the common stock will develop, or if one should develop, there is no assurance that it will be sustained. This severely limits the liquidity of the common stock, and would likely have a material adverse effect on the market price of the common stock and on our ability to raise additional capital.

We cannot assure you that our common stock will become liquid or that it will be listed on a securities exchange.

Until our common stock is listed on a national securities exchange such as the New York Stock Exchange or the Nasdaq National Market, we expect our common stock to remain eligible for quotation on the OTCBB, or on another over-the-counter quotation system. In those venues, however, an investor may find it difficult to obtain accurate quotations as to the market value of our common stock. In addition, if we fail to meet the criteria set forth in SEC regulations, various requirements would be imposed by law on broker-dealers who sell our securities to persons other than established customers and accredited investors. Consequently, such regulations may deter broker-dealers from recommending or selling our common stock, which may further affect the liquidity of our common stock. This would also make it more difficult for us to raise capital.

Our common stock is subject to the “penny stock” rules of the SEC and the trading market in our common stock is limited, which makes transactions in our common stock cumbersome and may reduce the value of an investment in the stock.

The SEC has adopted Rule 15g-9 which establishes the definition of a “penny stock,” for the purposes relevant to us, as any equity security that has a market price of less than $5.00 per share or with an exercise price of less than $5.00 per share, subject to certain exceptions. For any transaction involving a penny stock, unless exempt, the rules require:

that a broker or dealer approve a person’s account for transactions in penny stocks; and

the broker or dealer receive from the investor a written agreement to the transaction, setting forth the identity and quantity of the penny stock to be purchased.

In order to approve a person’s account for transactions in penny stocks, the broker or dealer must:

obtain financial information and investment experience objectives of the person; and

make a reasonable determination that the transactions in penny stocks are suitable for that person and the person has sufficient knowledge and experience in financial matters to be capable of evaluating the risks of transactions in penny stocks.

The broker or dealer must also deliver, prior to any transaction in a penny stock, a disclosure schedule prescribed by the SEC relating to the penny stock market, which, in highlight form sets forth:

the basis on which the broker or dealer made the suitability determination; and

that the broker or dealer received a signed, written agreement from the investor prior to the transaction.

Generally, brokers may be less willing to execute transactions in securities subject to the “penny stock” rules. This may make it more difficult for investors to dispose of common stock and cause a decline in the market value of stock.

Disclosure also has to be made about the risks of investing in penny stocks in both public offerings and in secondary trading and about the commissions payable to both the broker-dealer and the registered representative, current quotations for the securities and the rights and remedies available to an investor in cases of fraud in penny stock transactions. Finally, monthly statements have to be sent disclosing recent price information for the penny stock held in the account and information on the limited market in penny stocks.

The price of our common stock may become volatile, which could lead to losses by investors and costly securities litigation.

A trading market for our common stock may not develop or be liquid. If you invest in shares of our common stock, you may not be able to resell your shares above the price you pay and may suffer a loss of some or all of your investment.

Broad market and industry factors may adversely affect the market price of our common stock, regardless of our actual operating performance. The trading price of our common stock is likely to be highly volatile and could fluctuate in response to factors such as:

uncertainty associated with the timing of project development and completion;

extension or expiration of the production tax credit and other changes in government policy;

actual or anticipated variations in quarterly operating results;

volatility in market prices for electricity and Renewable Energy Certificates;

weather conditions that may affect our production;

changes in financial estimates by us or by any securities analysts who may cover our stock or our failure to meet the estimates made by securities analysts;

changes in the market valuations of other companies operating in our industry;

announcements by us or our competitors of significant acquisitions, strategic partnerships or divestitures;

additions or departures of key personnel; and

sales of our common stock, including sales of our common stock by our directors and officers or by our other principal stockholders.

The stock market is subject to significant price and volume fluctuations. In the past, following periods of volatility in the market price of a company’s securities, securities class action litigation has often been initiated against the company. Litigation initiated against us, whether or not successful, could result in substantial costs and diversion of our management’s attention and resources, which could harm our business and financial condition.

We currently do not intend to pay dividends on our common stock for the foreseeable future. As a result, your only opportunity to achieve a return on your investment is if the price of our common stock appreciates.

We currently do not expect to declare or pay dividends on our common stock for the foreseeable future. We expect to use future earnings, if any, to fund business growth. Therefore, stockholders will not receive any funds absent a sale of their shares. We may also enter into agreements in the future that prohibit or restrict our ability to declare or pay dividends on our common stock. As a result, your only opportunity to achieve a return on your investment will be if the market price of our common stock appreciates and you sell your shares at a profit.

Securities analysts may not initiate coverage or continue to cover our common stock, and this may have a negative impact on its market price.

The trading market for our common stock will depend in part on the research and reports that securities analysts publish about our business and our Company. We do not have any control over these analysts. There is no guarantee that securities analysts will cover the common stock. If securities analysts do not cover the common stock, the lack of research coverage may adversely affect its market price. If we are covered by securities analysts, and our stock is the subject of an unfavorable report, our stock price would likely decline. If one or more of these analysts ceases to cover our Company or fails to publish regular reports on us, we could lose visibility in the financial markets, which could cause our stock price or trading volume to decline.

You may experience dilution of your ownership interests due to the future issuance of additional shares of our common stock.

We are in a capital intensive business and we do not have sufficient funds to finance the growth of our business or the construction costs of our development projects or to support our projected capital expenditures. As a result, we will require additional funds from further financings, including tax equity financing transactions or sales of common or preferred stock, or other securities that are convertible into or exercisable for our common or preferred stock, to complete the development of new projects, fund project equity and pay the general and administrative costs of our business. We may also issue such securities in connection with hiring or retaining employees and consultants (including stock options issued under our equity incentive plans), as payment to providers of goods and services, in connection with future acquisitions or for other business purposes. Our Board of Directors may at any time authorize the issuance of additional common or preferred stock without common stockholder approval, subject only to the total number of authorized common and preferred shares set forth in our articles of incorporation. The preferences and rights of any preferred stock we issue will be as determined by our Board of Directors. The terms of equity securities issued by us in future transactions may be more favorable to new investors, and may include dividend and/or liquidation preferences, superior voting rights and the issuance of warrants or other derivative securities, which may have a further dilutive effect. The future issuance of such additional shares of common stock or preferred stock or other securities may create downward pressure on the trading price of our common stock. Any such future issuances of such additional shares of common stock or preferred stock or other securities may be at a price (have an exercise price) below the price you paid for your common stock or the price at which shares of the common stock are then traded.

ITEM 1B.

UNRESOLVED STAFF COMMENTS

None.

ITEM 2.

PROPERTIES

Properties

We generally do not own the property underlying our wind parks. Instead, we usually obtain easements from the landowners that give us the right to install our meteorological equipment, turbines, transmission lines and related equipment and prohibit the landowners from building other structures that would interfere with the operation or maintenance of the wind park. The terms of the easement agreements vary, but usually cover a development period, a construction period and a 20-year operational period, with our option to extend the operational period for an additional 30 years. Our easement agreements generally obligate us to make payments to the landowner based on revenues to be generated from assets located on the landowner’s property. During the construction phase of a particular wind park, we may acquire land for the siting of facilities needed by the transmission system operator to accommodate the wind park; we typically transfer these real estate interests to the transmission system operator once construction of the wind park is complete.

The land control agreements for our projects in development start as a lease option. The provisions of our land leases are substantially similar for all of our land-control contracts—both Lease Option Agreements and Lease Agreements. We will trigger the shift from lease option agreement to lease agreement when construction on a project begins. We have no leases currently, only lease options. Specific terms for individual landowners may differ occasionally, but none of our current leases options differs significantly from the general structure, which is summarized here:

	Option Agreement	Lease Agreement

Term:	5 years	40 years

Annual Payment:	$400/section	$2,500 per turbine plus
	(640 acres)	$1,000 per MW nameplate capacity

The lease option agreement provides us with the right to conduct wind studies, access the land, install meteorological towers and begin the permitting process with the landowners’ cooperation. The term of the option agreement is five years. We have a right of first refusal on other land owned by the landowner within one half mile of the proposed site. We pay the landowner at a rate of $100 per quarter-section of land (160 acres) annually, as well as a one-time payment for any crop loss.

Once the option to lease the land is exercised, the lease lays out the permitted uses of the property, which include wind resource evaluations, wind energy conversion systems, transmission facilities, waiver of setback and meeting with the owner. It also gives us the right to travel across the land, as well as to use access routes available. The lease prohibits the landowner from constructing any building on the land without prior approval, to prevent the obstruction of the wind.

The term of the lease is forty years from the date it is the lease option exercised, and we have the right to terminate the lease with 30 days notice, as can the landowner, but only if there are no improvements built for the wind park.

We pay the landowner annually $2,500 per turbine plus $1,000 per megawatt of nameplate capacity. If there are no turbines on the land, but there are improvements made, such as underground lines or roads, the landowner will receive a one-time payment of $2 per foot of underground improvement and $3 per foot of above ground improvement. The increase in real estate taxes caused by the increased value of the land due to turbines will be paid by us, while the original value of the real estate taxes will be paid by the landowner. Conservation Reserve Program (CRP) lands will be released from the CRP program if necessary, and we will pay any applicable fees/fines and will compensate the landowner for the loss of income through a one-time payment. Crop loss is also covered by using a calculation of current market price, number of acres damaged and average yield on the land. In addition, Crownbutte is required to maintain $1,000,000 in liability insurance.

Crownbutte may elect to make debt payments on behalf of the landowner in order to preserve its rights in the land by preventing foreclosure by a lender. The Company’s lease payment obligations would be offset by the amount of any such debt payment.

We also have the right to encumber our interests with debt to finance the wind park. We have the obligation to return the land to its original condition at the end of the lease term by removing all turbines and removing concrete down to four feet below the surface of the soil.

Description of Corporate Offices

We lease our corporate offices (approximately 3,000 square feet) at 111 5th Avenue NE, Mandan, ND 58554. The current lease for our office space is month-to-month, with a monthly rent of $1,500. We believe that our current facilities are adequate for our operations as currently conducted and if additional facilities are required, that we could obtain them at commercially reasonable prices. Once we have owned projects in operation, we will also require on-site project office space, which we intend to lease in the form of office trailers or existing built out space.

ITEM 3.

LEGAL PROCEEDINGS

From time to time, we may become involved in various lawsuits and legal proceedings which arise in the ordinary course of business. However, litigation is subject to inherent uncertainties, and an adverse result in these or other matters that may arise from time to time that may harm business.

Except for the matter described below, other than routine litigation arising in the ordinary course of business that we do not expect, individually or in the aggregate, to have a material adverse effect on us, there is no currently pending legal proceeding and, as far as we are aware, no governmental authority is contemplating any proceeding to which we are a party or to which any of our properties is subject, other than the Company’s applications for permits to install or erect wind turbines or weather-monitoring equipment, which are incidental to the business of the Company.

Although there can be no assurance as to the ultimate outcome, we have denied liability in the case pending against us, and we intend to defend vigorously such case. Based on information currently available, we believe the amount, or range, of reasonably possible losses in connection with the action against us not to be material to our consolidated financial condition or cash flows. However, losses may be material to our operating results for any particular future period, depending on the level of income for such period.

On August 19, 2008, Centre Square Capital, LLC filed a claim with the American Arbitration Association in the amount of $3,000,000 plus attorneys’ fees, interest, and arbitration costs in a demand for arbitration, claiming that the Company has not compensated it for introducing the Company to the firm that identified the Company’s private placement investors in March 2008 and thereafter. The Company maintained that the agreement pertains only to funds raised as a result of business with the People’s Republic of China. On March 16, 2009, the court dismissed the plaintiff’s claim and awarded the Company reimbursement of all attorney fees and costs related to the claim. A reimbursement of approximately $129,227 is payable to the Company.

As of the date of this report and as disclosed in the accompanying notes to audited consolidated financial statements for the year ended December 31, 2009, the Company has received $0 of the damages awarded on March 16, 2009. We believe there will be no recovery of this award.

Subsequent to the damages award, the Company was threatened with litigation over non-payment of attorney fees related to the Centre Square Capital arbitration and defense. On November 3, 2009, the Company was served with a lawsuit filed in the Philadelphia County Court of Common Pleas by Stradley, Ronon, Stevens & Young, LLP, seeking to recover $93,526 plus interest, attorneys’ fees, and costs. On December 14, 2009, the Company received a Notice of Intent to Take Default Judgment for the unpaid balance of $93,526. The Company has been working with the plaintiff to make payments on the debt. In exchange, the plaintiffs have agreed to postpone execution of the judgment.

As of the date of this report, the Company owes Stradley, Ronon, Stevens & Young, LLP $78,526. We anticipate paying the balance in full upon closing of the Gascoyne I financing, which is scheduled to occur on or before April 30, 2010. There is no guarantee the financing will be approved or that we will have the capital available to pay this debt.

If the Gascoyne I financing does not materialize or the Company cannot raise sufficient capital through the sales of its equity securities, there is no guarantee the judgment against us will not be exercised. Should they do so, the only liquid assets available to satisfy the judgment are the Company’s interconnect application deposits. Forfeiture of the deposits would significantly impair the status of our project queue positions. Loss of queue position may require new applications, additional deposits and development costs, and several years to obtain shovel-ready status.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

No matters were submitted to a vote of security holders, through the solicitation of proxies or otherwise, during the fourth quarter of the fiscal year covered by this Annual Report.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information and Holders

As of April 14, 2010, there were 32,257,472 shares of our common stock issued and outstanding and 8,350,034 shares issuable upon exercise of outstanding warrants. On that date, there were approximately 74 holders of record of shares of our common stock.

We have no outstanding shares of preferred stock.

Since December 2, 2009, our common stock has been quoted on the OTCBB under the trading symbol “CBWP.OB.” Through December 1, 2010, trades of our common stock were reported on the Pink Sheets (www.pinksheets.com) under the symbol “CBWP.PK.” The last reported sale price of our common stock on the OTCBB on April 14, 2010 was $0.29.

Trades in our common stock may be subject to Rule 15g-9 under the Exchange Act, which imposes requirements on broker/dealers who sell securities subject to the rule to persons other than established customers and accredited investors. For transactions covered by the rule, broker/dealers must make a special suitability determination for purchasers of the securities and receive the purchaser’s written agreement to the transaction before the sale.

The SEC also has rules that regulate broker/dealer practices in connection with transactions in “penny stocks.” Penny stocks generally are equity securities with a price of less than $5.00 (other than securities listed on certain national exchanges, provided that the current price and volume information with respect to transactions in that security is provided by the applicable exchange or system). The penny stock rules require a broker/dealer, before effecting a transaction in a penny stock not otherwise exempt from the rules, to deliver a standardized risk disclosure document prepared by the SEC that provides information about penny stocks and the nature and level of risks in the penny stock market. The broker/dealer also must provide the customer with current bid and offer quotations for the penny stock, the compensation of the broker/dealer and its salesperson in the transaction, and monthly account statements showing the market value of each penny stock held in the customer’s account. The bid and offer quotations, and the broker/dealer and salesperson compensation information, must be given to the customer orally or in writing before effecting the transaction, and must be given to the customer in writing before or with the customer’s confirmation. These disclosure requirements may have the effect of reducing the level of trading activity in the secondary market for shares of our common stock. As a result of these rules, investors may find it difficult to sell their shares.

The following table sets forth (i) for the period from December 2, 2009 through April 14, 2010, the high and low closing bid prices for our common stock, as reported on the OTCBB and (ii) for the period from January 1, 2008 through December 1, 2009, the range of high and low closing quotations for our common stock, as reported by Pink OTC Markets Inc. on its web site located at www.pinksheets.com. The quotations reflect inter-dealer prices, without retail mark-up, mark-down or commission and may not represent actual transactions. Our common stock is thinly traded and, thus, pricing of our common stock on the OTCBB does not necessarily represent its fair market value.

	High		Low

Fiscal Year Ended December 31, 2010
January 1, 2010 – April 14, 2010		0.910000		0.200000

Fiscal Year Ended December 31, 2009
December 2, 2009 – December 31, 2009		0.280000		0.130000
October 1, 2009 – December 1, 2009		0.360000		0.110000
Quarter ended September 30, 2009		0.550000		0.062000
Quarter ended June 30, 2009		0.550000		0.050000
Quarter ended March 31, 2009		4.400000		0.500000

Fiscal Year Ended December 31, 2008
Quarter ended December 31, 2008		0.550000		0.250000
Quarter ended September 30, 2008		6.570302		0.006570
Quarter ended June 30, 2008		0.006570		0.006570
Quarter ended March 31, 2008		0.013141		0.006570

Dividends

On March 11, 2008, a distribution of $153,333 was made by Crownbutte ND in conjunction with its change from “S corporation” to “C corporation” tax status. We have otherwise never declared or paid cash dividends on our equity securities. We do not intend to pay cash dividends on our common stock for the foreseeable future, but currently intend to retain any future earnings to fund the development and growth of our business. The payment of dividends, if any, on the common stock will rest solely within the discretion of our Board of Directors and will depend, among other things, upon our earnings, capital requirements, financial condition, and other relevant factors.

Securities Authorized for Issuance under Equity Compensation Plans

As of the end of the most recently completed fiscal year, we have not adopted any compensation plan (including any individual compensation arrangement) under which our equity securities are authorized for issuance.

See “Executive Compensation” for information regarding individual equity compensation arrangements received by our executive officers pursuant to their employment agreements with our Company.

Recent Sales of Unregistered Securities

On February 22, 2010, we had a closing of a private placement offering for an aggregate of 557,141 units of our securities at a purchase price of $0.35 per unit, for an aggregate cash consideration of $195,000, before deducting offering costs. Each unit consists of (i) one share of our common stock, (ii) a warrant to purchase one share of our common stock, exercisable for a period of four years at an exercise price of $1.50 per share, and (iii) a warrant to purchase one share of our common stock, exercisable for a period of four years at an exercise price of $2.50 per share.

The private placement offering was conducted pursuant to the exemption from the registration requirements of the federal securities laws provided by Regulation D and Regulation S promulgated under the Securities Act and Section 4(2) of the Securities Act. The common stock was offered and sold only to “accredited investors,” as that term is defined by Rule 501 of Regulation D, and/or to persons who were neither resident in, nor citizens of, the United States. No commissions were paid in connection with the offering.

On March 29, 2010, the Company issued a total of 400,000 shares of common stock in exchange for short-term loans from two of the Company’s stockholders. Terms of the loans are $100,000 payable in 60 days for 150,000 shares of common stock in lieu of interest, and $100,000 payable in 60 days for 250,000 shares of common stock in lieu of interest. Principal payments on both loans are due June 7, 2010. Our issuance of the shares in connection with the promissory notes was not registered under the Securities Act in reliance upon the exemption from registration provided by Section 4(2) of the Securities Act, which exempts transactions by an issuer not involving any public offering.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

Except in connection with the issuances described above, during the fourth quarter of the fiscal year covered by this Annual Report, no purchases were made by or on behalf of the Company or any “affiliated purchaser,” as defined in Rule 10b-18(a)(3) under the Exchange Act, of shares or other units of any class of the Company’s equity securities.

ITEM 6. SELECTED FINANCIAL DATA

Not applicable.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following discussion and analysis of financial condition and results of operations should be read in conjunction with our consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This discussion contains forward-looking statements that involve risks, uncertainties and assumptions. See “Note Regarding Forward-Looking Statements.” Our actual results could differ materially from those anticipated in the forward-looking statements as a result of certain factors discussed in “Risk Factors” and elsewhere in this Annual Report on Form 10-K.

Overview

Based in Mandan, ND, Crownbutte Wind Power, Inc. is an independent wind energy company focused exclusively on the development, ownership and operation of wind energy projects. One wind park developed by us from “green-field” or blank state to operation was purchased directly in 2002 by Basin Electric Power Cooperative (2.6 megawatts (MW) near Chamberlain, South Dakota. In addition to this operating park, we have completed various consulting activities with regional utilities and international energy companies. Our goal is to develop, own and operate merchant wind parks in the 20-60 MW capacity range. As of December 31, 2010, our portfolio of wind energy projects included approximately 638 MW (0 MW currently in operation) of prospective capacity in various stages of development primarily in the Dakotas and Montana.

The first wind park that we plan to build, own and operate is a 20 MW project called Gascoyne I located south of Dickinson, North Dakota. Our goal is to have approximately 20 MW of owned operating capacity by the end of 2010, and we target the construction and commissioning of approximately 40 MW of owned operating capacity in 2011. We do not currently and do not plan to act as an operator of wind parks we do not own.

Our business model focuses on the development of merchant parks. We do not plan to enter into power purchase agreements unless they are offered on favorable terms.

Going Concern

As indicated in the accompanying consolidated financial statements, we have incurred recurring losses from operations resulting in an accumulated deficit at December 31, 2009 of $5,539,075. These conditions raise substantial doubt as to our ability to continue as a going concern. There can be no assurance that we can sell stock or debt or that financing will be available to us in the future. In the event that we cannot create a source of recurring revenues or that we do not receive funds from other sources, we may be unable to continue to operate as a going concern. Our consolidated financial statements do not include any adjustments that might be necessary if we are unable to continue as a going concern.

Major Events and Material Transactions

Chamberlain, SD

In April 2001, we sold a fully-constructed 2.6 MW wind park near Chamberlain, SD, to Basin Electric Power Cooperative for $2,567,149 plus a maintenance contract through the end of 2002 worth $24,200.

Buffalo Ridge, MN

In July 2002, we entered into a consulting/advisory agreement with Suzlon Energy Limited, regarding a 20 MW wind park to be developed and constructed near Buffalo Ridge, MN. The agreement expired in December 2002.

Gascoyne I, ND

In December 2006, we sold development rights to a 20 MW park near Gascoyne, ND, to Boreal Energy Inc. for $325,000. Boreal did not proceed with construction of this park. In September, 2008, we re-acquired development rights to this site (Gascoyne I) from Boreal Energy for the same amount ($325,000).

As indicated in the accompanying consolidated financial statements, on February 15, 2010 the Company executed a non-binding term sheet with a private equity firm to provide $37.5 million debt financing for the Gascoyne I project. Terms of the financing provide for an 80% ownership interest to the lender with the Company retaining a 20% stake in the special-purpose entity. The consummation of this financing is subject to, among other things, satisfactory completion by the lender of all necessary technical and legal due diligence and satisfactory negotiation of all required definitive agreements necessary or desirable to effect the transaction. We anticipate a construction completion and operational date by the end of 2010 or early 2011.

Financing of this project may result in a development fee to Crownbutte of approximately $1 million. This project may also be eligible for a U.S. Treasury Department renewable energy grant equal to 30% of the authorized capital costs. This grant, if approved, would total approximately $10 million and provide additional funds to the Company through a 20% distribution of net profits/cash flow from the special purpose entity.

Baker, MT

In July 2007, we completed a consulting/advisory engagement with Montana-Dakota Utility (MDU) to oversee development and construction of a 19.5 MW wind park near Baker, MT, for total consideration of $473,000 (of which 400,000 was received in 2007 and the balance in 2008).

Berthold, ND

In January 2008, we entered into a joint development agreement with Evergreen Energy (the land owner) regarding a 60 MW park located near Berthold, ND. The parties agreed to split proceeds (2/3 Crownbutte, 1/3 Evergreen) in the event that the park is sold.

Gascoyne II, ND

In 2007, we received $70,100 to conduct feasibility analysis for a 200 MW site near Gascoyne, ND (different from the Gascoyne I project) on behalf of Westmoreland Coal. If the project was deemed feasible, then Westmoreland would have the right of first refusal to jointly develop the Gascoyne II site alongside Crownbutte. In May 2008, we elected to move forward on this site, and sold 40% of the rights to develop, construct, manage, and operate this 200 MW wind power project in southwest North Dakota to Westmoreland Coal. Westmoreland paid us $200,000 in consideration. Future capital contributions into the venture will be 50% each, although the share of capital will be 60% Crownbutte and 40% Westmoreland. We will be the managing party.

Ralls, TX

In July 2008, we agreed to purchase development rights from American Seawind Energy LLC for a 10 MW wind park near Ralls, TX. The agreement calls for a power purchase agreement (“PPA”), or qualifying facility (“QF”) off-take arrangement to be in place before construction. Purchase price was $1,500,000, with $200,000 due upon signature, $1,000,000 due on the earlier of construction start or March 2009, and the remaining $300,000 due upon construction completion. In December 2008, we determined that we would not pursue this project any further due to difficulties in securing a PPA and project financing.

Our Strategy

The electricity generated by all of our owned and operated wind parks will be sold under the best available arrangement for “off-taking” (the term for the act of accepting the flow of electricity offered by the generator, in this case the wind park owner/operator). In many wind developments in the past, this has occurred under a power purchase agreement (PPA) with a utility. In the Western North Dakota/Eastern Montana region, we have experienced the reality that PPA’s are difficult to secure, and when available, they have been at relatively unattractive price levels (e.g., $0.04/kWh). This phenomenon is likely the result of the relative abundance of cheap coal in the area, and a high number of coal-fired power plants owned by the local utilities.

Therefore, we have adopted the strategy of selling power on the local nodes of the Midwest Independent Systems Operator (“MISO”), using the available real-time spot market, as well as the day-ahead contract market. In this MISO footprint area, the relevant nodal prices have been trending upward for the past few years and have recently averaged over $0.048/kWh (see graph below), which we believe is an attractive enough price to make project finance models workable for the raising of construction capital.

The reliance on the merchant market (i.e., the lack of PPAs) can be a significant barrier to achieving project finance with tax equity investors (as described below), many of whom seek the security of long-term PPAs with off-takers. The possibility that the spot price of electricity will drop is also a risk to our business strategy. Finally, we are exploring the viability of hedging against the possible drop of local electricity prices. In the MISO footprint, the availability of solid hedging instruments (with high correlations to the local power market price histories) has been the focus of our investigations. A risk remains that a viable hedging methodology is not possible in the MISO footprint, which would represent an overall risk to the success of the business model, and is a possible barrier to achieving project financing.

We have entered into negotiations with and have received quotes from multiple suppliers (including GE, ACCIONA, Gamesa and DeWind) for purchase of turbines for our first planned park construction, with a delivery target of September 2010. We believe that the turbines that we require for our project development schedule will be available on a timely basis provided that we can obtain turbine financing. Generally, turbine suppliers require up-front payments upon execution of a turbine supply agreement and significant progress payments well in advance of turbine delivery. See the discussion of “Project Finance” below. We expect this supply will be sufficient and timely for our anticipated construction schedule.

The primary challenges we face include our limited operating history, our lack of any owned operating wind parks and expected dependence on a limited number of owned operating wind parks for the foreseeable future, increasing costs in all areas of our business, tighter terms and conditions on debt and tax equity financing available to us, the amount of capital we need to raise to consummate our business plan, the availability of turbines, the uncertainty created by efforts to extend the production tax credit and the vulnerability of our wind parks to meteorological and atmospheric conditions. Our ability to complete the projects in our development pipeline and achieve our targeted capacity is subject to these and a number of other risks and uncertainties as described in the “Risk Factors” section of this Annual Report.

Since 1999, we have focused on seeking the most attractive wind regimes at sites that are very close to existing transmission lines with high likelihood of available electricity transmission capacity. We believe our attention to the existing transmission infrastructure will contribute to a lower construction cost due to a lessened need for transmission plant upgrades, as well as improved time to achieve an interconnection agreement with the local utility and systems operator. Selecting optimal sites on butte tops (i.e., consistently high winds with low turbulence) should ensure high net capacity factors. As a result, we have amassed a pipeline of attractive wind parks, the first of which are ready for construction financing.

Green-field development of wind park sites is a process that generally takes approximately 24 months and $200,000 to $300,000 of development expense. The sequence of steps that we follow in this process is generally as follows:

Identify the transmission capability

Conduct topographical studies

Configure an initial park array

Procure the necessary land lease options

Install site-specific meteorological instrumentation

Accumulate sufficient meteorological data

Select turbine type

Prepare a wind report (by a certified consulting meteorologist)

Apply for local/state/federal permitting and transmission queue position

10.

Secure interconnect agreement

11.

Prepare site design, including geotechnical studies for the foundations

12.

Execute turbine supply agreement

13.

Retain construction contractor(s)

14.

Prepare the final site designs (including high voltage systems, access roads, junction boxes etc.)

The additional steps after completion of the development phase are:

15.

Finalize project financing

16.

Order long lead-time items

17.

Construction

18.

Turbine Commissioning

19.

Operation and Maintenance.

Our current pipeline of projects includes 12 projects totaling 638 MW (0 MW currently in operation) of potential capacity. The table below provides information on our projects in development, including the stage of development based on the 14 steps outlined above:

Crownbutte Projects in Development

			Park Size		Net Capacity			Development
	Project	State	(MW)		Factors			Steps Completed
1	Gascoyne I	ND		20		41.2	%	Steps 1- 10
2	New England	ND		60		43.0	%	Steps 1-8
3	Wibaux	MT		20		40.0	%	Steps 1-9
4	Elgin	ND		20		38.0	%	Steps 1-9
5	Berthold	ND		60		37.0	%	Steps 1-9
6	Carson	ND		20		37.0	%	Steps 1-6
7	Gascoyne II	ND		200		43.6	%	Steps 1-9
8	Tappen	ND		98		40.0	%	Steps 1-6
9	Monarch	MT		60		39.0	%	Steps 1-6
10	Mobridge	SD		40		36.0	%	Steps 1-5
11	Scobey	MT		20		41.0	%	Steps 1-6
12	Big Sandy	MT		20		35.0	%	Steps 1-4

We believe we are ready to make the transition to owner-operator, in addition to developer, of wind energy generation sites. This transition would result in the addition of a new stream of revenue from the sales of electricity generated by owned wind energy assets, as well as the sale of associated Renewable Energy Certificates (“RECs”). We intend to construct as many of the projects in our pipeline as possible. The total number we are able to construct will be a function of our success in securing project financing.

Since we will need to cover our corporate overhead and expenses during the period until cash flows from owned and operated wind projects generate enough income to do so, it will be necessary to sell the development rights to at least one of the projects currently in our pipeline. Which project’s development rights are sold has not yet been determined and is subject to the desires of potential purchasers more than to us.

In March and April 2008, Crownbutte ND sold an aggregate of 1,100,000 units of its securities in a private placement at a purchase price of $0.50 per unit, for an aggregate cash consideration of $550,000, before deducting offering costs. Each unit consisted of one share of Crownbutte ND common stock and a warrant to purchase one share of Crownbutte ND common stock, exercisable for a period of three years at an exercise price of $0.50 per share. (Upon the closing of the merger, these units converted into an aggregate of 1,100,000 shares of our common stock and warrants to purchase 1,100,000 shares of our common stock with the same terms.)

Concurrently with the closing of the merger on July 2, 2008, we consummated a private placement of 1,350,000 units of our securities at a purchase price of $0.50 per unit, for an aggregate cash consideration of $675,000, before deducting offering costs. Each unit consists of one share of our common stock and a warrant to purchase one share of our common stock, exercisable for a period of two years at an exercise price of $2.50 per share. On July 18, 2008, we sold an additional 850,000 units for an aggregate cash consideration of $425,000; on August 12, 2008, we sold an additional 678,000 units for an aggregate cash consideration of $339,000; and on September 8, 2008, we sold an additional 240,000 units for an aggregate cash consideration of $120,000, all as part of the same private placement.

In February 2010, we consummated a private placement of 557,141 units of our securities at a purchase price of $0.35 per unit, for an aggregate cash consideration of $195,000, before deducting offering costs. Each unit consists of (i) one share of our common stock, (ii) a warrant to purchase one share of our common stock, exercisable for a period of four years at an exercise price of $1.50 per share, and (iii) a warrant to purchase one share of our common stock, exercisable for a period of four years at an exercise price of $2.50 per share.

We plan to raise an additional approximately $1 million through private placements of equity by the end of 2010, the proceeds of which, together with cash on hand, will be used for general corporate expenses associated with the hiring of new staff required to accelerate our development activities, as well as move into our new owner-operator business model, which requires oversight of construction of projects, as well as the operations and maintenance of projects after construction is complete. However, we may be unable to secure this additional financing on terms acceptable to us, or at all, at times when we need such financing. Our inability to raise these additional funds on a timely basis could prevent us from achieving our business objectives and could have a negative impact on our business, financial condition, results of operations and the value of our securities. We do not anticipate a need to raise additional equity financing beyond this $1 million to fund development, operating and maintenance costs. These fundings do not include project financing. See “—Project Finance” and “—Liquidity and Capital Resources” below.

Green-field Development and Sale of Development Rights

The current business model for Crownbutte is to develop likely sites from a green-field or blank-slate status into a state that is “construction-ready” or “shovel-ready.” This process can take two to four years and from $200,000-$400,000 of expenses for each project. Development rights to projects can be sold at any time to entities that take responsibility for completing any remaining development, raising project finance and completing construction. The development rights to a park may change hands several times before construction is actually started.

Generally speaking, pricing is discussed and negotiated on a “per-megawatt” basis. Prices for the purchase of development rights for specific parks can vary widely based on a number of factors, including:

engineered generation capacity

wind regime

topography

amount of land under control

nearest transmission inter-connect point

transmission capacity of nearest transmission line(s)

on-site meteorological data gathering equipment

completed wind resource assessments

permitting

interconnection application deposits

We intend to continue development of projects currently in our pipeline. We also intend to sell one to two parks per year to interested parties for the purpose of covering corporate expenses until such time we are able to generate sufficient revenues and cash flow solely from the ownership and operation of developed parks. We estimate that on-going green-field development activities cost approximately $800,000 to $850,000 per year in total. Although there can be no guarantee, because pricing varies and the number of transactions is small, we estimate that the sale of 20 to 40 MW of development rights per year should cover our green-field development costs.

Project Finance

The basic gating element in constructing wind parks is the raising of project finance. We estimate (based on most recent quotes from suppliers, contractors, and vendors) that the cost of constructing a wind park is $1.8 to $2 million per megawatt of rated generation capacity. For the Gascoyne I project (20 MW), the first wind park we plan to construct, this means a necessary project financing amount of $38,000,000.

Failure to secure the required project financing is a significant risk to our operating plan. Without project financing, we have no alternatives to monetization of our development efforts other than the sale of the development rights to entities that are able to assemble the necessary project finance to enable construction. Inability to raise project finance would mean that we would be relegated to being solely a green-field developer and not an owner-operator. In this scenario, total profits would be significantly smaller in magnitude than in the case of success with the owner/operator model.

We plan on financing our projects one or two at a time with the best available combination of debt, tax equity financing and equity capital. At the initial stage of a project’s development, for example, we could use a combination of equity capital and turbine supply loans to cover development expenses and turbine costs. Turbine supply loans would be employed to finance approximately 60-90% of the cost of a project’s turbines. Once a project moves to the construction phase, we could use a combination of equity capital and construction loans to finance the construction of the project. Proceeds from the construction loans are typically used to fund construction and installation costs as well as to retire the turbine supply loans. Finally, once a project is complete and commercial operations begin, we would permanently finance the project through a combination of term loans and equity financing transactions, the proceeds of which would be used to retire the construction loans and provide for a return of a portion of equity capital. Although the percentage of each of these three forms of permanent financing varies regionally and by project, tax equity financing (discussed below) typically represents a majority of a project’s permanent financing.

We continue to pursue project financing opportunities with a large number of finders and private equity firms for the Elgin and Wibaux projects, which total 40 MW. There can be no guarantees these efforts will result in the necessary funding for these projects. In both cases, the projects themselves would be owned by a special-purpose entity and would be financed on a limited recourse basis, and could benefit from the production tax credit (“PTC”) or investment tax credit (“ITC”), or the U.S. Treasury Department renewable energy grant program in lieu of investment tax credits or production tax credits, and the Modified Accelerated Cost Recovery System of the Internal Revenue Code (“MACRS”) tax benefits during the operating life of the project itself (typically 20 years).

Turbine supply loans

The majority of the total cost of a wind energy project is attributable to turbine purchases. Our turbine purchases will be our principal capital expenditure. During the construction of our first planned park, Gascoyne I, turbine costs will comprise roughly $28 million of a total estimated $38 million capital cost.

In recent years, the combined effect of a limited number of turbine suppliers, the weakening dollar, rising commodity costs and increasing demand for turbines has led to escalating turbine prices. To mitigate supply-related uncertainty, we will seek to secure and finance our anticipated turbine needs in advance of our targeted installation dates. We are looking at quotes from GE and from Gamesa (both established suppliers), as well as from DeWind (a newer entrant into the U.S. wind turbine market) and Acciona. We have seen some evidence of softening turbine prices and shorter delivery lead times as the financial market turmoil during the autumn of 2008 have slowed the installation of new wind capacity. While we currently have no turbines under contract, we expect that the turbines that we require for our project development schedule will be available on a timely basis provided that we can obtain turbine financing.

Generally, turbine suppliers require up-front payments upon execution of a turbine supply agreement and significant progress payments well in advance of turbine delivery. We expect to finance our turbine supply agreements through a combination of turbine supply loans and equity capital. Equity capital contributions to each project are anticipated to vary from 10-100%, depending on the terms available from turbine supply loan lenders.

Development financing

We have historically funded the development expenditures of our turn-key projects, primarily consisting of permitting, community outreach and meteorological expenses, through income derived from consulting projects, construction oversight, or outright sale of partially-developed wind parks. In the future, we expect to fund the development of our owned and operated wind energy projects with a combination of cash flows from operations (sale of electricity, sale of RECs, and sale of partially-completed projects), the proceeds of the completed private placements of equity, and future debt and/or equity offerings.

Construction loans

After we have developed a wind energy project to the point where we are prepared to commence construction, we typically expect to enter into a limited recourse construction loan. Proceeds from construction loans are typically used to retire turbine indebtedness and to pay construction costs, including costs to construct roads, substations, transmission lines and the balance of plant. Construction loans are generally secured by the project’s assets. In certain instances we may enter into a construction loan for a single project, while in other instances we may be able to finance multiple projects through a single credit facility. We will also use equity capital contributions (from other investors and potentially our own as described above) to fund a portion of each project’s construction costs.

We would forego the need for construction loans (as well as turbine supply loans) if we are able to secure 100% debt or 100% equity-based investment for any given project. A 100% debt financing would be done on a limited recourse basis and be secured by the project assets and our equity. In a 100% equity financing, the outside equity investors would contribute all of the project costs as equity in return for an 80% to 90% share of the returns. However, while we are exploring these possibilities, these structures have not in the past been the norm in the wind generation industry and may not be available. As discussed in the Recent Developments section and elsewhere in this report, the proposed 100% debt financing with 80% ownership stake for our Gascoyne I project is unique and we do not anticipate it as the norm for future projects.

Financing upon commencement of commercial operations

Once construction of a wind energy project is completed and commercial operations commence, we would seek to finance the project on a long-term basis through a combination of term loans and tax equity financing, as described in more detail below.

Term loans. Term loans provide long-term debt financing and are repaid with project cash flows. In conjunction with term loans, a project that has a PPA may maintain a separate credit facility to provide letters of credit required under the PPA. We expect our project subsidiaries that raise term loan financing generally to secure these term loans through pledges of our equity interests in the project companies.

Tax equity financing. We generally will seek to secure tax equity financing to provide the majority of each project’s permanent capital needs for projects constructed after 2010. In a typical tax equity financing, we expect to receive a capital investment for a portion of a project’s cost in exchange for an equity interest in our subsidiary that owns the project. These equity interests entitle the tax equity investors to receive a portion of the project’s cash distributions from electricity sales and related hedging agreements, PTCs and taxable income or loss until such investors reach an agreed rate of return on their investment, which we typically expect to occur in ten years. The availability of tax equity financing depends on federal tax attributes that encourage renewable energy development. These attributes primarily include (i) renewable energy PTCs, which are federal income tax credits related to the quantity of renewable energy produced and sold during a taxable year and (ii) accelerated depreciation of renewable energy assets as calculated under MACRS.

The PTC incentive currently provides a $21 federal tax credit per megawatt hour (“MWh”) for a renewable energy facility that uses wind, geothermal or “closed-loop” bioenergy fuel sources in each of the first ten years of its operation, and applies to facilities that are placed in service before the end of 2012. These facilities will continue to benefit from the current PTC incentive until the end of the ten-year period from the date on which the facilities are placed in service. Our current tax equity financing model is substantially dependent on the PTC incentive, and to the extent it is not extended our anticipated growth will be adversely affected. The growth of our business depends upon the extension of the expiration date of the PTC, which currently expires on December 31, 2012, and other federal and state governmental policies and standards that support renewable energy development.

The Tax Reform Act of 1986 established MACRS as the method to calculate depreciation for federal income tax purposes. Under MACRS, wind power assets are provided a depreciable life of five years, which is substantially shorter than the 15- to 20-year depreciable lives associated with traditional power generation facilities. Accelerated depreciation results in tax losses in the early stages of a wind energy project’s life. Typically, 90% of a wind energy project’s assets qualify for five-year accelerated depreciation under MACRS.

The amount of the capital investment made by our tax equity investors will be determined by discounting the projected future value of the cash distributions from electricity sales and related hedging agreements, PTCs and taxable income or loss that the tax equity investors will be entitled to receive until such investors reach an agreed investment return, which we typically expect to occur in ten years. The after-tax discount rate used for this calculation will be an agreed-upon targeted investment return for the tax investor. As described in more detail in the table below, prior to achieving the targeted investment return, our tax equity investors would receive substantially all of the project’s cash distributions from electricity sales and related hedging agreements, PTCs and taxable income or loss. Following achievement of the targeted investment return, the allocation of the project’s cash distributions from electricity sales and related hedging agreements, PTCs and taxable income or loss would “flip” or reverse from our tax equity investors to us so that we would receive substantially all of the project’s cash distributions from electricity sales and related hedging agreements, PTCs and taxable income or loss from that point forward. If the project outperforms expectations, the flip will occur sooner, and if a project underperforms, it will take longer for the flip to occur.

To date, the wind industry’s tax equity investors have been large financial institutions with significant taxable income. However, the unprecedented upheaval in the financial markets in the U.S. and around the world in recent months has significantly lowered or eliminated profits achieved by many financial institutions, making tax equity investing less available in general. After giving effect to a tax equity financing, we will retain day-to-day operational and management control of the applicable project. However, our tax equity financing agreements are expected to provide the tax equity investors with a number of approval rights, including approvals of annual budgets, indebtedness, incurrence of liens, sales of assets outside the ordinary course of business and litigation settlements. Tax equity investors do not receive a lien on the project’s assets.

Although the economic terms of each tax equity financing will vary substantially, the following table provides an illustration of an allocation to tax equity investors of cash distributions, PTCs and taxable income or loss that may characterize a tax equity financing. The column titled “Cash Distributions” reflects the apportionment of cash distributions from electricity sales and related hedging agreements; the column titled “PTCs” reflects the allocation of PTCs for U.S. federal income tax purposes; and the column titled “Taxable Income or Loss” reflects the allocation of taxable income or loss for U.S. federal income tax purposes.

	Cash Distributions						PTCs (1)						Taxable Income or Loss
	Project Owner			Tax Equity Investors			Project Owner			Tax Equity Investors			Project Owner			Tax Equity Investors
Year 1 to Flip Date (2)		30	%		70	%		1	%		99	%		1	%		99	%
Thereafter		95	%		5	%		95	%		5	%		95	%		5	%

(1)	PTCs lapse after ten years of commercial operations, and the assets are generally fully depreciated five years after commercial operations commence.

(2)	Actual flip dates, as discussed above, vary and depend on the date the tax equity investors earn the agreed upon targeted investment return.

Hedging

Our ownership and operation of wind energy projects will expose us to volatility in market prices of electricity and RECs. In an effort to stabilize our returns from electricity sales, we intend to carefully review the electricity sale options for each of our development projects. As part of this review, we will assess the appropriateness of entering into a fixed price PPA and/or a financial hedge. If we sell our electricity into a liquid independent systems operator (“ISO”) market, we may enter into a financial hedge with institutional investors in order to stabilize our projected revenue stream.

Under the terms of our anticipated financial hedges, we would not be obligated to physically deliver or purchase electricity, but we would receive payments for certain quantities of electricity based on a fixed price and would be obligated to pay the market electricity price for the same quantities of electricity. Thus, if market prices of electricity increase, we are obligated to make payments under these financial hedges. Our financial hedges will cover quantities of electricity that we estimate we can produce with a high degree of certainty. As a result, gains or losses under the financial hedges should be offset by decreases or increases in our revenues from spot sales of electricity in liquid ISO markets. However, the actual amount of electricity we generate from operations may be materially different from our estimates for a variety of reasons, including variable wind conditions, catastrophic events such as fires, earthquakes, storms and changes in weather patterns due to climate change. To the extent actual amounts produced fall short of the quantities covered in our financial hedges, we will not be hedged and we will be exposed to commodity price risk. In the event a project does not generate the amount of electricity covered by the related hedge, we could incur significant losses under the financial hedge if electricity prices rise substantially above the fixed prices provided for in the hedge. If a project generates more electricity than is covered by the relevant hedge, the excess production will not be hedged and the revenues we derive will be subject to market price fluctuations.

We may seek to sell forward a portion of our RECs in an effort to hedge against future declines in REC prices. If our projects are unable to generate the amount of electricity required to earn the RECs sold forward or if we are unable for any reason to qualify our electricity for RECs in relevant states, we may incur significant losses.

Material trends and uncertainties

Please refer to the “Risk Factors” section for an in-depth discussion of the risks that face the Company and its investors. We are pursuing our business plan against the backdrop of a business, financial and competitive environment whose characteristics represent material factors that affect the quality and amount of our revenues, costs, financing prospects and liquidity. Among these factors are:

●

Demand for and price of electricity. We seek to develop and eventually construct wind parks that are aimed at generating and selling electricity on established spot markets in the Midwest Independent Systems Operator (MISO) footprint. The possibility that the price of electricity will fall and stay low for a protracted period is a basic uncertainty inherent in the merchant model, which seeks to sell electricity on a spot market. Please refer to the more detailed discussion in the “Description of Business—Demand for Electricity.”

●

Costs of alternative methods of generation. Sustained declines in the prices of fossil fuels, and drops in the costs of other alternative energy technologies (such as solar), may also impair our income prospects.

Price of natural gas. The prices for natural gas in 2009 were volatile and ended the year at, or below, the prices during the beginning of the year. Natural gas is a major source of fuel for electricity generation in the U.S., so any declines in the price of natural gas will negatively impact electricity prices and therefore our prospective income.

Price of oil. The price of oil in 2009 climbed steadily since the beginning of the year. This may cause some increase in electricity prices (increasing our prospective income), however this effect is likely small since oil is not used as a major fuel for electricity generation in the U.S., but does have some impact on the price of natural gas, which is a source of fuel for electricity generation.

●

Regulatory environment facing independent generators of electricity. We can offer no assurances that the current regulatory environment will not become more stringent in the future, and raise the cost of compliance. Utilities are competing generators of electricity who also own transmission infrastructure. Utilities may be able to influence legislation in their favor at the expense of generators who do not own transmission infrastructure. In such a case, the construction costs for our wind parks would rise, and impair the profitability of our prospective business model.

These uncertainties are inherent to the wind energy business and are difficult or impossible to effectively mitigate, particularly for a company like us with limited resources.

●

Tax incentives and government subsidies. The American Recovery and Reinvestment Act of February 2009 includes provisions that extend the PTC/ITC tax benefits available to the wind industry until December 31, 2012. Long term success for Crownbutte will depend on the continuance of such subsidies beyond 2012.

●

Condition of capital and credit markets .

Ability to raise project finance for construction of wind projects. Late 2008 and early 2009 has been a time of great difficulty for the financial markets, and credit has become very difficult to obtain, especially for developers such as Crownbutte, who have not raised construction financing before. Inability to raise project finance will mean that we must rely on sale of development rights for income.

Ability to raise private placement capital for general corporate expenses. Poor performance of the equity markets has impaired our abilities to raise capital via a private placement of common stock. We plan to raise approximately $1 million through private placement of equity by the end of 2010, but there can be no assurance that we will be successful.

●

Ability to sell the development rights for individual green-field development projects. Our near term income will depend on the sale of development rights for one or two wind parks per year. Because such a sale can take weeks or months to negotiate, we cannot well control the timing of such income. If such a sale does not occur before funds are depleted by ordinary expenditures, then we will face significantly adverse liquidity problems.

These uncertainties are inherent in the wind energy business and are difficult or impossible to effectively mitigate, particularly for a company like us with limited resources. Any or all of the above factors may be such that successful pursuit of our strategy may be seriously impaired and may represent a potentially significant adverse impact on earnings and liquidity. The Company will closely monitor changes in any of these areas to determine if they are material and will seek to adjust its business operations to adapt to these changes as they are identified, although there can be no assurance we will be successful in doing so.

Results of Operations

We are an exploration stage company and have generated minimal revenues from operations to date.

Fiscal Years 2009 and 2008 Compared

	For years ended December 31,
	2009			2008			$ Change			% Change

Sale of project development rights	$	-		$	200,000		$	(200,000	)		-100	%
Consulting revenues		-			73,020			(73,020	)		-100	%

Total revenues		-			273,020			(273,020	)		-100	%

Cost of revenues
Project development rights		-			34,593			(34,593	)		-100	%
Consulting		-			3,482			(3,482	)		-100	%
Total cost of revenues		-			38,075			(38,075	)		-100	%

Gross profit		-			234,945			(234,945	)		-100	%

Operating expenses:
General and administrative (includes stock based compensation of $702,702 and $2,739,974 for stock and warrants issued for services in 2008)		1,828,235			4,169,687			(2,341,452	)		-56	%
Depreciation expense		32,459			21,039			11,420			54	%
Total operating expenses		1,860,694			4,190,726			(2,330,032	)		-56	%

Net operating loss		(1,860,694	)		(3,955,781)			2,095,087			-53	%

Other income (expenses):
Interest income		935			11,282			(10,347	)		-92	%
Other income		60,772			-			60,772			100	%
Interest expense		(4,094	)		-			4,094			100	%
Loss on sale of fixed assets		(18,369	)		-			18,369			100	%
Bad debt expense		(1,722	)		-			1,722			100	%
Total other income (expenses)		37,522			11,282			26,240			233	%

Net loss	$	(1,823,172	)	$	(3,944,499	)	$	2,121,372			54	%

For the year ended December 31, 2009, revenues declined to $0 from $273,020 in 2008. This reflects the timing and lumpiness of income from sale of brown-field sites as well as from consulting. No new sales of development rights or new consulting projects were secured during 2009. As described in the “Risk Factors” section and in the discussion on Material Trends and Uncertainties, we cannot be assured of success in our endeavors to sell development rights, to secure consulting contracts, or to raise the necessary project finance required to construct and operate wind parks for the sale of electricity.

We believe that 2009 was a difficult year for the wind industry as a whole due to the uncertainties surrounding the global economic environment (which made financing of all types more difficult). In this environment of uncertainty, there was a decline in the number of potential purchasers of development rights to new wind parks. We are encouraged by the passage of the American Recovery and Reinvestment Act of 2009, which extends the PTC for three years to 2012, offers an alternative ITC option to the PTC, and, for projects beginning construction before the end of 2010, offers a one-time grant equal to 30% of the authorized capital costs of the project in lieu of investment tax credits or production tax credits. These new incentives have mitigated the adverse effects of continued tightening in the credit markets and have contributed to an improvement in the overall economic climate for the wind industry. However, to date, we have been unsuccessful in securing any additional sales of development rights, and there can be no assurance we will be able to sell development rights in the future. We have entered into a non-binding agreement to obtain $37.5 million debt financing for our Gascoyne I project, as discussed elsewhere within this report. The consummation of this financing is subject to, among other things, satisfactory completion by the lender of all necessary technical and legal due diligence and satisfactory negotiation of all required definitive agreements necessary or desirable to effect the transaction. We anticipate a construction completion and operational date by the end of 2010 or early 2011. There can be no assurance, however, that this project financing effort will be successful.

Cost of Revenues

During 2009, we had no cost of revenues due to no revenue earned for the year. This is a decrease of $38,075 compared to 2008.

Operating Expenses

A large portion of the total 2009 operating expenses is share-based compensation relating to key employees and awards made in 2008. The Company recognized $702,702 in share-based compensation in 2009 compared to $2,739,974 in 2008. The decrease in compensation expense of $2,037,272 accounted for most of the Company’s $2,121,372 improvement in earnings for 2009 versus 2008.

Research and development expenses related to the Company’s projects, decreased in 2009 to $147,151 compared to $638,443 for 2008. The significant decrease is mainly due to the increased activity and investments made in 2008 to purchase development rights and to bring projects closer to the shovel-ready phase for 2009. Most of 2009’s focus for the Company shifted from development to seeking financing for late development stage projects. No new significant investments were made in 2009.

Legal, accounting, and other professional fees (which includes costs related to finance costs of raising private placement investment and ongoing filing requirements) were higher in 2009 versus 2008. Professional fees expenses for 2009 totaled $417,294 compared to $273,865 recorded in 2008. A significant portion of the additional $143,429 recorded in 2009 includes legal defense fees related to the Centre Square Capital litigation from 2008.

Other Non-Operating Income and Expenses

The Company incurred interest expense totaling $4,094 in 2009 compared to $0 in 2008. The increase in interest expense is due to finance charges on credit cards payable and late fees incurred in 2009 caused by the Company’s increased accounts payable and accrued liabilities.

The Company incurred a loss of $18,369 on sale of fixed assets in 2009 compared to $0 for 2008. Three vehicles and one trailer were sold during the year to generate cash for operating expenses.

Other income of $60,772 was recorded in 2009, most of it ($53,214) due to the write off of a legal bill owed by the Company. There was no other income for 2008.

The Company received $935 interest income for 2009 compared to $11,282 for 2008. The decrease of $10,347 was due to the depletion of cash and redemption of interest-bearing certificates of deposit early in 2009.

Liquidity and Capital Resources

The Company experienced significant liquidity issues in 2009 compared to 2008. Expenses related to the reverse merger, private placements, and increased investment in project development activities late 2008 continued into 2009, depleting the Company’s cash reserves. Further compounding the issue, the credit market turmoil of late 2008 continued well into 2009 and to the present, making the task of obtaining financing even more difficult. The Company also incurred significant legal and other expenses due to litigation and the ongoing accounting and public reporting expenses.

In an effort to cut costs, staff were reduced in 2009 from eight to four, retaining only key employees until the Company can successfully procure financing for one or more projects, generate revenue from the sale of project development rights or consulting, or raise sufficient funds through private placements.

The Company has accrued significant liabilities and has a working capital deficit of $652,292 as of December 31, 2009 compared to positive working capital of $300,200 on December 31, 2008. In 2009, we used $560,875 cash in operations compared to $1,158,901 used in operations for 2008. The decrease in cash used for 2009 is mainly due to large increases in accounts payable and accrued liabilities for 2009 and no additional investment in interconnect application deposits compared to 2008.

Future efforts to generate positive cash flow depend on Crownbutte’s success in selling development rights to parks in the short term, and constructing wind parks to generate electricity sales in the long term. If we are successful at closing the pending Gascoyne I financing, we anticipate receipt of approximately $1,000,000 developer fee to be paid out of the financing. Receipt of these funds will allow the Company to eliminate most of our liabilities and obligations through the date of financing, however, we will still be dependent upon sales of project development rights, consulting revenues, or other sources of cash flow until such time our parks are operational and generating sufficient revenues to meet corporate overhead.

Cash flows from investing activities for 2009 totaled $169,471 compared to cash used in investing activities in 2008 of $181,640. The increase in cash from investing for 2009 related to redemption of certificates of deposit totaling $152,030 and sales of fixed assets compared to $170,499 fixed assets purchased in 2008.

Cash flows from financing activities for 2009 totaled $104,023 compared to $1,519,500 in 2008. Sources of cash for 2009 included officer loan proceeds of $44,380, stockholder loans of $20,000 and proceeds from exercise of warrants totaling approximately $40,000. In 2008 the Company received most of its financing funds from private placement activities. A dividend of $153,333 was paid to the original stockholders in 2008.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements that have or are reasonably likely to have a current or future effect on our financial condition, changes in financial condition, revenues or expenses, results of operations, liquidity, capital expenditures or capital resources that is material to investors.

Critical Accounting Policies

Revenue Recognition

The Company recognizes revenue in accordance with guidance issued by the Financial Accounting Standards Board (“FASB”) on revenue recognition, which requires 1) evidence of an agreement, 2) delivery of the product or services has occurred 3) at a fixed or determinable price, and 4) assurance of collection within a reasonable period of time.

Further, some revenues are recognized using the percentage of completion method of accounting. The Company believes that the use of the percentage of completion method is appropriate as the Company has the ability to make reasonably dependable estimates of the extent of progress towards completion, contract revenues and contract costs. The percentage to completion is measured by monitoring progress using records of actual time, materials and other costs incurred to date on specific projects compared to the total estimated project requirements, which corresponds to the costs related to earned revenues. Estimates of total project requirements are based on prior experience of customization, delivery and acceptance of the same or similar technology and are reviewed and updated regularly by management. Provisions for estimated losses on uncompleted contracts are made in the period in which such losses are first determined, in the amount of the estimated loss on the entire contract.

The Company currently functions in two business areas: as a wind park developer and as a consulting and advisory service to power utilities. During 2008 the Company recognized revenues from consulting and advising services to power utilities (Consulting revenues). The Company made no sales and had no consulting revenues for the year ended December 31, 2009.

Consulting services revenue is recognized under guidance that differs from contract services revenue. Consulting services revenue is recognized when delivery of the service has occurred; the customer has already received the service, and along with other revenue recognition criteria, qualifies the transaction as a sale. Whereas, contract services revenue is recognized when delivery of the product or service has yet to be completed yet the transaction still qualifies as a sale. When recognizing contract services revenue, prior to the project’s start, the Company estimates the cost at each stage of the project. As time passes and the stages are completed, the contractor recognizes an estimate of the revenue that has been earned based on the percentage of the estimated costs that have already been incurred. Using the percentage of completion method allows revenues and their associated expenses to be recognized in the same accounting period according to the matching principle, even if the customer has yet to receive delivery of the goods and services, or if the goods and services have not been completed by the Company.

Cost of Revenues

The Company includes all direct costs related to its contract and sale of development rights revenues in cost of revenues. The types of costs include materials and supplies and subcontractor fees and expenses specific to the project or contract. Additionally, allocations of payroll, taxes, and benefits are added to cost of revenues based on time worked on each project. Any project expenses not directly related to revenue-generating contracts or sales are expensed to research and development within general and administrative expenses.

Research and Development

The Company expenses research and development as incurred.

Stock-Based Compensation

The Company accounts for the grant of stock and warrants awards in accordance with ASC Topic 718, Compensation – Stock Compensation (ASC 718). ASC 718 requires companies to recognize in the statement of operations the grant-date fair value of warrants and stock options and other equity based compensation.

The Company uses the Black-Scholes option valuation model for estimating the fair value of traded options. This option valuation model requires the input of highly subjective assumptions including the expected stock price volatility.

See the accompanying notes to consolidated audited financial statements for additional discussion of critical accounting policies (Note 3 – Summary of Significant Accounting Policies).

New Accounting Pronouncements

In June 2009, the FASB issued authoritative guidance which eliminates the exemption for qualifying special-purpose entities from consolidation requirements, contains new criteria for determining the primary beneficiary of a variable interest entity, and increases the frequency of required reassessments to determine whether a company is the primary beneficiary of a variable interest entity. The guidance is applicable for annual periods beginning after November 15, 2009 and interim periods therein and thereafter. The Company does not expect the adoption of this standard to have a material effect on its financial position or results of operations.

EITF Issue No. 07-5 (ASC 815), “Determining Whether an Instrument (or embedded Feature) is Indexed to an Entity’s Own Stock” (EITF 07-5) was issued in June 2008 to clarify how to determine whether certain instruments or features were indexed to an entity’s own stock under EITF Issue No. 01-6 (ASC 815), “The Meaning of “Indexed to a Company’s Own Stock” (EITF 01-6) (ASC 815),. EITF 07-5(ASC 815), applies to any freestanding financial instrument (or embedded feature) that has all of the characteristics of a derivative as defined in FAS 133, for purposes of determining whether that instrument (or embedded feature) qualifies for the first part of the paragraph 11(a) scope exception. It is also applicable to any freestanding financial instrument (e.g., gross physically settled warrants) that is potentially settled in an entity’s own stock, regardless of whether it has all of the characteristics of a derivative as defined in FAS 133 (ASC 815), for purposes of determining whether to apply EITF 00-19 (ASC 815). EITF 07-5(ASC 815) does not apply to share-based payment awards within the scope of FAS 123(R), Share-Based Payment (FAS 123(R) (ASC 718)). However, an equity-linked financial instrument issued to investors to establish a market-based measure of the fair value of employee stock options is not within the scope of FAS 123(R) and therefore is subject to EITF 07-5(ASC 815).

In January 2009, the FASB issued FSP EITF 99-20-1 (ASC 325), to amend the impairment guidance in EITF Issue No. 99-20 (ASC 325) in order to achieve more consistent determination of whether an other-than-temporary impairment (“OTTI”) has occurred. This FSP amended EITF 99-20 (ASC 325) to more closely align the OTTI guidance therein to the guidance in Statement No. 115 (ASC 320, 10-35-31). Retrospective application to a prior interim or annual period is prohibited. The guidance in this FSP was considered in the assessment of OTTI for various securities at December 31, 2008.

On June 5, 2003, the United States Securities and Exchange Commission (“SEC”) adopted final rules under Section 404 of the Sarbanes-Oxley Act of 2002 (“Section 404”), as amended by SEC Release No. 33-9072 on October 13, 2009. Commencing with its annual report for the year ending December 31, 2010, the Company will be required to include a report of management on its internal control over financial reporting. The internal control report must include a statement of:

Management’s responsibility for establishing and maintaining adequate internal control over its financial reporting;

Management’s assessment of the effectiveness of its internal control over financial reporting as of year- end; and

The framework used by management to evaluate the effectiveness of the Company’s internal control over financial reporting.

Furthermore, it is required to file the auditor’s attestation report separately on the Company’s internal control over financial reporting on whether it believes that the Company has maintained, in all material respects, effective internal control over financial reporting.

In August 2009, the FASB issued the FASB Accounting Standards Update No. 2009-04 “Accounting for Redeemable Equity Instruments - Amendment to Section 480-10-S99” which represents an update to section 480-10-S99, distinguishing liabilities from equity, per EITF Topic D-98, Classification and Measurement of Redeemable Securities. The Company does not expect the adoption of this update to have a material impact on its consolidated financial position, results of operations or cash flows. In August 2009, the FASB issued the FASB Accounting Standards Update No. 2009-05 “Fair Value Measurement and Disclosures Topic 820 – Measuring Liabilities at Fair Value”, which provides amendments to subtopic 820-10, Fair Value Measurements and Disclosures – Overall, for the fair value measurement of liabilities. This update provides clarification that in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more of the following techniques: 1. A valuation technique that uses: a. The quoted price of the identical liability when traded as an asset b. Quoted prices for similar liabilities or similar liabilities when traded as assets. 2. Another valuation technique that is consistent with the principles of topic 820; two examples would be an income approach, such as a present value technique, or a market approach, such as a technique that is based on the amount at the measurement date that the reporting entity would pay to transfer the identical liability or would receive to enter into the identical liability. The amendments in this update also clarify that when estimating the fair value of a liability, a reporting entity is not required to include a separate input or adjustment to other inputs relating to the existence of a restriction that prevents the transfer of the liability. The amendments in this update also clarify that both a quoted price in an active market for the identical liability when traded as an asset in an active market when no adjustments to the quoted price of the asset are required are Level 1 fair value measurements. The Company does not expect the adoption of this update to have a material impact on its consolidated financial position, results of operations or cash flows.

In September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-08 “Earnings Per Share – Amendments to Section 260-10-S99”,which represents technical corrections to topic 260-10-S99, Earnings per share, based on EITF Topic D-53, Computation of Earnings Per Share for a Period that includes a Redemption or an Induced Conversion of a Portion of a Class of Preferred Stock and EITF Topic D-42, The Effect of the Calculation of Earnings per Share for the Redemption or Induced Conversion of Preferred Stock. The Company does not expect the adoption of this update to have a material impact on its consolidated financial position, results of operations or cash flows.

In September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-09 “Accounting for Investments-Equity Method and Joint Ventures and Accounting for Equity-Based Payments to Non-Employees”. This update represents a correction to Section 323-10-S99-4, Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee. Additionally, it adds observer comment Accounting Recognition for Certain Transactions Involving Equity Instruments Granted to Other Than Employees to the Codification. The Company does not expect the adoption to have a material impact on its consolidated financial position, results of operations or cash flows.

In September 2009, the FASB issued the FASB Accounting Standards Update No. 2009-12 “Fair Value Measurements and Disclosures Topic 820 – Investment in Certain Entities That Calculate Net Assets Value Per Share (or Its Equivalent)”, which provides amendments to Subtopic 820-10, Fair Value Measurements and Disclosures-Overall, for the fair value measurement of investments in certain entities that calculate net asset value per share (or its equivalent). The amendments in this update permit, as a practical expedient, a reporting entity to measure the fair value of an investment that is within the scope of the amendments in this update on the basis of the net asset value per share of the investment (or its equivalent) if the net asset value of the investment (or its equivalent) is calculated in a manner consistent with the measurement principles of Topic 946 as of the reporting entity’s measurement date, including measurement of all or substantially all of the underlying investments of the investee in accordance with Topic 820. The amendments in this update also require disclosures by major category of investment about the attributes of investments within the scope of the amendments in this update, such as the nature of any restrictions on the investor’s ability to redeem its investments at the measurement date, any unfunded commitments (for example, a contractual commitment by the investor to invest a specified amount of additional capital at a future date to fund investments that will be made by the investee), and the investment strategies of the investees. The major category of investment is required to be determined on the basis of the nature and risks of the investment in a manner consistent with the guidance for major security types in U.S. GAAP on investments in debt and equity securities in paragraph 320-10-50-1B. The disclosures are required for all investments within the scope of the amendments in this update regardless of whether the fair value of the investment is measured using the practical expedient. The Company does not expect the adoption to have a material impact on its consolidated financial position, results of operations or cash flows.

In October 2009, the FASB issued guidance for amendments to FASB Emerging Issues Task Force on EITF Issue No. 09-1 “Accounting for Own-Share Lending Arrangements in Contemplation of a Convertible Debt Issuance or Other Financing” (Subtopic 470-20) “Subtopic”. This accounting standards update establishes the accounting and reporting guidance for arrangements under which own-share lending arrangements issued in contemplation of convertible debt issuance. This Statement is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2009. Earlier adoption is not permitted. The Company does not expect the adoption to have a material impact on its consolidated financial position, results of operations or cash flows.

A variety of proposed or otherwise potential accounting standards are currently under study by standard setting organizations and various regulatory agencies. Due to the tentative and preliminary nature of those proposed standards, management has not determined whether implementation of such proposed standards would be material to our consolidated financial statements.

ITEM 8.

FINANCIAL STATEMENTS AND SUPPLEMENTAL DATA

Our audited consolidated financial statements as of, and for the years ended, December 31, 2009 and 2008 are included beginning on Page F-1 immediately following the signature page to this report. See Item 15 for a list of the financial statements included herein.

ITEM 9.

CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A(T)

CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer evaluated the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of December 31, 2009, the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures as of December 31, 2009 were not effective to ensure that the information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to the Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding disclosure. A controls system cannot provide absolute assurance that the objectives of the controls system are met, and no evaluation of controls can provide absolute assurance that all control issues and instances of fraud, if any, within a company have been detected.

Our Chief Executive Officer and Chief Financial Officer are responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act). Our internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance of achieving their control objectives. Furthermore, smaller reporting companies face additional limitations. Smaller reporting companies employ fewer individuals and find it difficult to properly segregate duties. Often, one or two individuals control every aspect of the Company’s operation and are in a position to override any system of internal control. Additionally, smaller reporting companies tend to utilize general accounting software packages that lack a rigorous set of software controls.

We have identified the following material weaknesses in our internal control over financial reporting:

Lack of Independent Board of Directors and Audit Committee

Management is aware that an audit committee composed of the requisite number of independent members along with a qualified financial expert has not yet been established. Considering the costs associated with procuring and providing the infrastructure to support an independent audit committee and the limited number of transactions, management has concluded that the risks associated with the lack of an independent audit committee are not sufficient to justify the creation of such a committee at this time. Management will periodically reevaluate this situation.

Lack of Segregation of Duties

Management is aware that there is a lack of segregation of duties at the Company due to the small number of employees dealing with general administrative and financial matters. However, at this time management has decided that considering the abilities of the employees now involved and the control procedures in place, the risks associated with such lack of segregation are low and the potential benefits of adding employees to clearly segregate duties do not justify the substantial expenses associated with such increases. Management will periodically reevaluate this situation.

Officers’ Certifications

Appearing as Exhibits 31.1 and 31.2 to this Annual Report are “Certifications” of our Chief Executive Officer and Chief Financial Officer which are required pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (the “Section 302 Certifications”). This section of the Annual Report contains information concerning the evaluation of disclosure controls and procedures referred to in the Section 302 Certifications. This information should be read in conjunction with the Section 302 Certifications for a more complete understanding of the topics presented.

Changes in Internal Control Over Financial Reporting

There have been no changes in our internal control over financial reporting that occurred during the quarter ended December 31, 2009 that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

ITEM 9B. OTHER INFORMATION

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE

Executive Officers and Directors

Our executive officers and directors are as follows:

Name	Age	Position

Timothy H. Simons	63	Chief Executive Officer, President and Director

Manu Kalia	39	Chief Financial Officer

Ross D. Mushik	51	Director

Terry Pilling	39	Director and Executive Vice President

Background of Executive Officers and Directors

Timothy H. Simons, Chief Executive Officer, President and Director, founded Crownbutte ND in 1999 and has been involved in the wind power industry since 1996. Following the merger in July 2008, Mr. Simons became our Chief Executive Officer and President and a member of the Board of Directors. From 1991 through 2002, he was a teacher in the public school systems of Bismarck and Mandan, North Dakota. After founding Crownbutte ND in 1999, he taught part time, devoting over 40 hours per week to the Company.

In 2002 Mr. Simons was asked to join the newly established Upper Great Plains Transmission Coalition (the “UGPTC”). The UGPTC was formed by the Governor of North Dakota in cooperation with Minnesota and South Dakota in order to address electrical transmission problems, so that the coal, hydro and wind resources in the area could be better utilized. In addition to membership in the UGPTC, Mr. Simons is on the Steering Committee and is co-chairman of the Transmission Bottleneck Committee of the UGPTC.

Manu Kalia, Chief Financial Officer, has been our Chief Financial Officer since September 15, 2008. Mr. Kalia has 13 years of high tech and financial management experience. He served as CEO of ProMana Solutions, Inc. (web-based payroll services) from July 2006 to July 2008, CFO of ARC International, PLC (semiconductors IP and embedded software) from October 2002 to June 2006, CFO of Tradeworx Inc. (statistical-arbitrage financial analytics/ hedge fund) from March 2001 to September 2002, and CEO of Open Source Creations Inc. (online collaboration) from August 2000 to February 2001. Prior to that, Mr. Kalia spent time as an investment banker for Commonwealth Associates from July 1999 to July 2000, as an analyst for Sanford Bernstein from April 1998 through June 1999, and as a manager at Lucent Technologies Bell Laboratories from September 1995 through March 1998. Mr. Kalia holds a Bachelor in Engineering Sciences (cum laude) from Dartmouth College, and an MBA from the Amos Tuck School of Business Administration at Dartmouth.

Ross D. Mushik, Director, was appointed to the Board of Directors on June 4, 2009. Mr. Mushik is the principal owner and operator of Ross Lawn and Snow Services, LLC, a small business located in Mandan, ND, which has been in operation since August 2007. Prior to being a full-time entrepreneur, Mr. Mushik was employed with state government in various positions within the fields of accounting and finance for approximately 22 years. He served as Administrative Services Manager for the ND Department of Emergency Services, a position he held from October 2001 to August 2007 and as Account/Budget Specialist December 1997 to October 2001. From January 1991 to December 1997, Mr. Mushik was an Account Budget Specialist at the ND Office of Intergovernmental Assistance. From August 1988 to December 1990, he worked for American Express Financial Services as a Financial Planner, and in state government from July 1983 to August 1988 as a Field Tax Inspector and Legal Auditor for the ND State Tax Department. Mr. Mushik has a Masters of Business Administration from the American Graduate School of International Management in Glendale, Arizona and a Bachelor of Arts Degree from Jamestown College in Jamestown, ND. Mr. Mushik serves as Secretary and Treasurer for two fraternal organizations, the Masons and the Shriners.

Terry Pilling, Director and Executive Vice President, has been a member of the Board of Directors since September 2008 and our Executive Vice President since February 2010. From September 2008 to February 2010, Mr. Pilling served as our Vice President of Operations and Technology. Mr. Pilling was an assistant professor of the Physics Department at the North Dakota State University from August 2004 to August 2008. His professional experience includes Visiting Researcher, Joint Astronomy Centre and the James Clerk Maxwell radio telescope on Mauna Kea, Hilo, Hawaii from May 2006 to August 2006; Postdoctoral Research Associate, Institute of Theoretical and Experimental Physics, Moscow from September 2003 to June 2004 and Postdoctoral Research Associate, Joint Institute for Nuclear Research, Dubna from September 2003 to June 2004. Prior to that, Mr. Pilling worked as Science Editor for the House of Knowledge Publishing Company in London, England from September 2002 to August 2003, as a teaching assistant for the North Dakota State University from September 1998 to August 2002 and as its physics department Network Systems Administrator and Webmaster September 1999 to August 2002. Mr. Pilling obtained his Ph.D. in High Energy Particle Physics and Gravitation from North Dakota State University in 2002. He achieved an M.Sc. in Theoretical and Experimental Nuclear Physics from Saskatchewan Accelerator Laboratory in 1998 and a B.Sc. in Physics and Engineering Physics from the University of Saskatchewan in 1996. Mr. Pilling has received professional recognition from the North Dakota State University as an Odney Award nominee in 2008 and a Gunkelman Award nominee in 2006. He was a National Science Foundation EPSCoR Research Fellow in 2001 and received the Physics and Engineering Physics Convocation Award in 1996 from the University of Saskatchewan.

Code of Ethics

We have not formally adopted a code of ethics that governs all of our employees, including our CEO, CFO, principal accounting officer or persons performing similar functions.

Board of Directors; Committees; Audit Committee Financial Expert

The Board of Directors currently consists of three members. Directors serve until their successors are duly elected or appointed. Messrs. Simon and Pilling are not “independent” as defined in the Nasdaq Stock Market Listing Rules. Mr. Mushik may be considered to be “independent,” but the Board has made no determination as yet. None of our directors is an “audit committee financial expert” as defined Item 407 of Regulation S-K. With a Board of only three directors, we do not have a separate audit committee or any other committee.

Shareholder Communications

Currently, we do not have a policy with regard to the consideration of any director candidates recommended by security holders. To date, no security holders have made any such recommendations.

ITEM 11. EXECUTIVE COMPENSATION

Summary Compensation Table

The following table sets forth information concerning the total compensation paid or accrued by us during the last two fiscal years ended December 31, 2009 to (i) all individuals that served as our principal executive officer or acted in a similar capacity for us at any time during the fiscal year ended December 31, 2009; (ii) all individuals that served as our principal financial officer or acted in a similar capacity for us at any time during the fiscal year ended December 31, 2009; and (iii) all individuals that served as executive officers of ours at any time during the fiscal year ended December 31, 2009 that received annual compensation during the fiscal year ended December 31, 2009 in excess of $100,000.

Name and Principal Position(s) (a)	Year (b)	Salary ($) (c)		Bonus ($) (d)	Stock Awards ($) (e)	Option Awards ($) (f)		Non-Equity Incentive Plan Compensation ($) (g)	Change in Pension Value and Nonqualified Deferred Compensation Earnings ($) (h)	All Other Annual Compensation ($) (i)		Total ($) (j)

Timothy H. Simons	2009	$	105,600	-	-			-	-	$	1,080	$	106,680
President & CEO	2008	$	105,600	-	-		-	-	-	$	3,168	$	108,768

Manu Kalia	2009	$	100,000	-	-	$	702,702	-	-	$	-	$	802,702
CFO	2008	$	20,833	-	-	$	251,000	-	-	$	-	$	271,833

Terry Pilling	2009	$	100,000	-	-	$	-	-	-	$	2,250	$	102,250
Executive Vice President(1)	2008	$	16,666	-	-	$	-	-	-	$	-		16,666

Ryan Fegley,	2009	$	30,513	-	-	$	-	-	-	$	915	$	31,428
VP of Project Development(2)	2008	$	46,167	-	-	$	2,488,000	-	-	$	1,385	$	2,535,552

(1) From September 17, 2008 to February 15, 2010, Mr. Pilling was Vice President of Operations and Technology.

(2) Mr. Fegley resigned as a director and Vice President of Project Development as of May 15, 2009.

Each of Messrs. Kalia and Pilling is, and prior to his resignation Mr. Fegley was, party to an employment agreement with the Company governing his compensation. See “Employment Agreements with Executive Officers” below. There are no other written or unwritten agreements with other executive officers, other than Messrs. Kalia and Pilling. Mr. Simons’ compensation is determined annually by the Board of Directors.

Chronology of Stock and Option Awards

In June 2008, Timothy Simons was granted warrants to purchase 1,000,000 shares of restricted common stock at an exercise price of $0.10 per share, vesting immediately and with a term of five years. These warrants were granted to Mr. Simons as part of a negotiated transaction and were not issued as compensation.

In June 2008, Ryan Fegley was granted warrants to purchase 5,000,000 shares of restricted common stock at an exercise price of $0.01 per share, vesting immediately and with a term of three years.

In September 2008, Manu Kalia entered into an employment agreement with Crownbutte wherein he was to be granted 1,000,000 shares of restricted common stock, vesting quarterly in four equal portions beginning January 1, 2009. The employment agreement has since been amended (on January 1, 2009) to change the grant of shares into a grant of warrants to purchase the same number of shares (1,000,000) at an exercise price of $0.001 per share, vesting on the same four-quarter schedule. Manu Kalia was also granted warrants to purchase 1,000,000 shares at an exercise price of $0.001 per share, vesting 100% on September 15, 2009.

In each accounting period, the value of each stock or option award that vests shall be expensed according to the principles of FAS123(R).

In August 2007, the Company established a SIMPLE retirement plan. The Company matches employee contributions up to 3% of gross wages. The Company’s contributions to the plan were $6,776 for the year ended December 31, 2008 and $6,378 for the year ended December 31, 2009.

OUTSTANDING EQUITY AWARDS AT FISCAL YEAR-END

OPTION AWARDS											STOCK AWARDS
Name (a)	Number of Securities Underlying Unexercised Options (#) Exercisable (b)			Number of Securities Underlying Unexercised Options (#) Unexercisable (c)		Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) (d)		Option Exercise Price ($) (e)		Option Expiration Date (f)	Number of Shares or Units of Stock That Have Not Vested (#) (g)		Market Value of Shares or Units of Stock That Have Not Vested ($) (h)		Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (i)		Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested (#) (j)
Timothy H. Simons		1,000,000	(1)		-		-	$	0.10	July 2, 2013		-		-		-		-
Manu Kalia		-			1,000,000		-	$	0.001	Sept. 15, 2013		1,000,000	$	500,000		-		-

(1)	Mr. Simons received these warrants as part of a negotiated transaction and not as compensation.

Employment Agreements with Executive Officers

On September 15, 2008, the Company entered into an employment agreement with Manu Kalia to serve as its Chief Financial Officer. Pursuant to the agreement, Mr. Kalia will receive annual compensation of $100,000, until the Company raises an additional $3,000,000 in private placement of its stock, at which time Mr. Kalia will receive annual compensation of $150,000. The Company granted to Mr. Kalia warrants to purchase 1,000,000 shares of its restricted common stock at, which shares vest quarterly in four equal installments beginning on January 1, 2009. Mr. Kalia also received warrants to purchase 1,000,000 shares of the Company’s common stock at an exercise price of $0.001 per share, which warrants become exercisable after Mr. Kalia’s has been continuously employed by the Company for a period of 12 months. In addition, Mr. Kalia is entitled to participate in the benefits from time to time in effect for the Company’s employees holding similar positions, along with vacation, sick and holiday pay in accordance with policies established and in effect from time to time. The Company may terminate the employment agreement with notice if (i) the Company discontinues operation of its business or is forced to reduce its personnel due to lack of work or (ii) Mr. Kalia becomes “permanently disabled” (as defined in the agreement). If Mr. Kalia breaches any of the terms of the agreement or if there is just cause for termination, the Company may terminate Mr. Kalia without notice. Mr. Kalia may terminate his employment with one month’s notice. On January 1, 2009, Mr. Kalia’s employment agreement was amended to change the original grant of 1,000,000 shares into warrants to purchase 1,000,000 restricted common shares at an exercise price of $0.001 per share. The vesting schedule remains unchanged, vesting quarterly in four equal portions starting on January 1, 2009.

On September 17, 2008, the Company entered into an employment agreement with Terry Pilling to serve as its Chief of Operations and Technology. Pursuant to the agreement, Mr. Pilling will receive annual compensation of $100,000. He will have the opportunity to acquire stock options through a Company plan if and when the Company adopts an equity incentive plan, and the Company will contribute one-half of the value of the stock as part of his compensation, not to exceed 15% of the his gross annual salary. Mr. Pilling is entitled to participate in the benefits from time to time in effect for the Company’s employees holding similar positions, along with vacation, sick and holiday pay in accordance with policies established and in effect from time to time. The Company may terminate the employment agreement with notice if (i) the Company discontinues operation of its business or is forced to reduce its personnel due to lack of work or (ii) Mr. Pilling becomes “permanently disabled” (as defined in the agreement). If Mr. Pilling breaches any of the terms of the agreement or if there is just cause for termination, the Company may terminate Mr. Pilling without notice. Mr. Pilling may terminate his employment with one month’s notice. On February 15, 2010, Mr. Pilling was promoted to Executive Vice President.

On November 27, 2007, the Company entered into an employment agreement with Ryan Fegley to serve as a Project Manager to develop wind projects. Pursuant to the agreement, Mr. Fegley received annual compensation of $35,000. Mr. Fegley was also a director of the Company. Mr. Fegley resigned as director and Vice President of Project Development as of May 15, 2009. In anticipation of the Merger, in June 2008, the Company granted Mr. Fegley warrants to purchase 5,000,000 shares of Crownbutte ND common stock, exercisable for three years, at an exercise price of $0.01 per share. At the merger, this warrant was exchanged for warrants to purchase 5,000,000 of Company common stock, at an exercise price of $0.01 per share.

Director Compensation

We do not award stock options to our directors for their services as directors. Our directors are paid $500 per year and reimbursed for reasonable and necessary out-of-pocket expenses incurred in connection with their service to us, including travel expenses.

ITEM 12.

SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

The following tables set forth certain information regarding the beneficial ownership of our common stock as of April 14, 2010, by (i) each person who, to our knowledge, owns more than 5% of the common stock; (ii) each of our directors and executive officers; and (iii) all of our executive officers and directors as a group. Unless otherwise indicated in the footnotes to the following tables, each person named in the table has sole voting and investment power, except to the extent such power may be shared with a spouse, and that person’s address is c/o Crownbutte Wind Power, Inc., 111 5th Avenue NE, Mandan, ND 58554. Shares of common stock subject to options or warrants currently exercisable or exercisable within 60 days of that date are deemed outstanding for computing the share ownership and percentage of the person holding such options and warrants, but are not deemed outstanding for computing the percentage of any other person.

Name and Address of Beneficial Owner	Amount and Nature of Beneficial Ownership		Percent of Class+

Timothy H. Simons (1)		13,000,000		39.1	%
Ross D. Mushik		*		*
Manu Kalia (2)		2,082,164		6.1	%
Terry Pilling		*		*
Directors and executive officers as a group (1) – (2)		15,082,164		42.8	%

Dan Gefroh		5,000,000		15.7	%

* Less than one percent

+ Based on 32,257,472 shares of common stock issued and outstanding as of April 14, 2010.

(1)	Includes 1,000,000 shares of common stock issuable upon exercise of warrants currently exercisable or exercisable within 60 days.

(2)	Includes warrants to purchase 2,000,000 shares of restricted stock that are currently exercisable or exercisable within 60 days.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS,

Other than as disclosed below and in this Annual Report, there have been no transactions, or currently proposed transactions, in which we were or are to be a participant and the amount involved exceeds the lesser of $120,000 or 1% of the average of our total assets at year end for the last two completed fiscal years and in which any of our directors, executive officers or beneficial holders of more than 5% of our outstanding common stock, or any of their respective immediate family members, has had or will have any direct or material indirect interest.

In June 2008, Timothy Simons agreed to surrender 3,000,000 shares of Crownbutte ND common stock, in exchange for a warrant to purchase 1,000,000 shares of Crownbutte ND common stock, exercisable for five years, at an exercise price of $0.10 per share. At the merger, this warrant was exchanged for a warrant to purchase 1,000,000 of our common stock as a result of the merger, at an exercise price of $0.10 per share. Also upon the closing of the merger, Mr. Simons received 12,000,000 shares of our common stock in exchange for 12,000,000 shares of Crownbutte ND common stock. Between May 21 and September 29, 2009, the Company borrowed a total of $44,380 from Mr. Simons. These loans are non-interest bearing and payable on demand.

Ryan Fegley, a director and Vice President of Project Development of the Company until May 15, 2009, was party to an employment agreement with the Company and received compensation thereunder. See the “Executive Compensation” section. In June 2008, in consideration of his services, Crownbutte ND granted to Mr. Fegley a warrant to purchase 5,000,000 shares of Crownbutte ND common stock, exercisable for three years, at an exercise price of $0.01 per share. At the merger, this warrant was exchanged for a warrant to purchase 5,000,000 of our common stock, at an exercise price of $0.01 per share.

On September 15, 2008, Manu Kalia has entered into an employment agreement with the Company and receives compensation thereunder. See the “Executive Compensation” section. At the closing of the merger on July 2, 2008, we issued 5,400,000 shares of our common stock (on a pre-reverse stock split basis) to Mr. Kalia pursuant to a Memorandum of Understanding between the Company and Mr. Kalia.

On September 17, 2008, Terry Pilling has entered into an employment agreement with the Company and receives compensation thereunder. Mr. Pilling is compensated $100,000 annually as Executive Vice President. See the “Executive Compensation” section.

Ross Mushik, a director appointed to the Board in June 2009, owns and operates Ross Lawn and Snow Services, LLC and conducts business with the Company providing snow removal services. Amounts billed to the Company for snow removal average less than $1,000 annually.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES

Audit Fees.

The aggregate fees billed to us by our principal accountant for services rendered during the fiscal years ended December 31, 2009 and 2008 are set forth in the table below:

Fee Category	Fiscal year ended December 31, 2009		Fiscal year ended December 31, 2008
Audit fees (1)	$	44,500	$	44,000
Audit-related fees (2)	$	30,000	$	0
Tax fees (3)	$	0	$	0
All other fees (4)	$	0	$	0
Total fees	$	0	$	0

(1)

“Audit fees” consists of fees billed for professional services rendered for the audit of consolidated financial statements, for reviews of our interim consolidated financial statements included in our quarterly reports on Forms 10-Q and for services that are normally provided in connection with statutory or regulatory filings or engagements.

(2)

“Audit-related fees” consists of fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our consolidated financial statements, but are not reported under “Audit fees,” consisting of fees associated with the Company’s Registration Statement on Form S-1.

(3)	“Tax fees” consists of fees billed for professional services relating to tax compliance, tax planning, and tax advice.

(4)	“All other fees” consists of fees billed for all other services.

Audit Committee’s Pre-Approval Practice

Our Board currently has no separate Audit Committee. Accordingly, the entire Board of Directors functions as our audit committee. Our Board is directly responsible for the appointment, compensation, retention and oversight of the work of any registered public accounting firm engaged by us for the purpose of preparing or issuing an audit report or performing other audit, review or attest services for us, and each such registered public accounting firm must report directly to the Board. It is our Board’s policy to approve in advance all audit, review and attest services and all non-audit services (including, in each case, the engagement fees therefor and terms thereof) to be performed by our independent auditors, in accordance with applicable laws, rules and regulations. During fiscal 2009 and 2008, all such services were pre-approved by the Board in accordance with this policy.

Our Board selected Sherb & Co., LLP as our independent registered public accounting firm for purposes of auditing our financial statements for the year ended December 31, 2009. In accordance with Board’s practice, Sherb & Co., LLP was pre-approved by the Board to perform these audit services for us prior to its engagement.

PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

Financial Statement Schedules

The consolidated financial statements of Crownbutte Wind Power, Inc. are listed on the Index to Financial Statements on this annual report on Form 10-K beginning on page F-1.

All financial statement schedules are omitted because they are not applicable or the required information is shown in the financial statements or notes thereto.

Exhibits

The following Exhibits are being filed with this Annual Report on Form 10-K:

In reviewing the agreements included or incorporated by reference as exhibits to this Annual Report on Form 10-K, please remember that they are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about us or the other parties to the agreements. The agreements may contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties have been made solely for the benefit of the parties to the applicable agreement and:

should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

may apply standards of materiality in a way that is different from what may be viewed as material to you or other investors; and

were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. Additional information about us may be found elsewhere in this Annual Report on Form 10-K and our other public filings, which are available without charge through the SEC’s website at http://www.sec.gov.

Exhibit No.		Description

2.1	(1)	Agreement and Plan of Merger and Reorganization, dated as of July 2, 2008, by and among Crownbutte Wind Power, Inc. (f/k/a ProMana Solutions, Inc.), a Nevada corporation (the “Registrant” or the “Company”), Crownbutte Acquisition Sub Inc., a North Dakota corporation, and Crownbutte Wind Power, Inc., a North Dakota corporation

2.2	(1)	Articles of Merger of Crownbutte Acquisition Sub Inc. with and into Crownbutte Wind Power, Inc., a North Dakota corporation, filed as of July 2, 2008

3.1	(1)	Restated Articles of Incorporation of the Registrant, filed as of July 2, 2008

3.2	(1)	Amended and Restated Bylaws of the Registrant, adopted as of June 2008

4.1	(1)	Form of the certificate representing the Registrant’s common stock, par value $0.001 per share

4.2	(1)	Form of Warrant of the Registrant issued to former holders of warrants of Crownbutte Wind Power, Inc., a North Dakota corporation, issued in connection with a private placement offering by Crownbutte Wind Power, Inc., a North Dakota corporation, completed in April 2008

Exhibit No.		Description

4.3	(1)	Form of Investor Warrant of the Registrant, issued in connection with a private placement offering by the Registrant completed in September 2008

4.4	(1)	Form of Lock-Up Agreement between the Registrant and Timothy H. Simons and Dan Gefroh

10.1	(1)	Split-Off Agreement, dated as of July 2, 2008, by and among the Registrant, Pro Mana Technologies, Inc., Crownbutte Wind Power, Inc., a North Dakota corporation, Robert A. Basso and Lawrence J. Kass

10.2	(1)	General Release Agreement, dated as of July 2, 2008, by and among the Registrant, Pro Mana Technologies, Inc., Crownbutte Wind Power, Inc., a North Dakota corporation, Robert A. Basso and Lawrence J. Kass

10.3	(1)	Escrow Agreement, dated as of July 2, 2008, by and among the Registrant, Timothy H. Simons and Gottbetter & Partners, LLP

10.4	(1)	Form of Subscription Agreement by and between Crownbutte Wind Power LLC and certain investors

10.5	(1)	Form of Subscription Agreement by and between the Registrant and certain investors

10.6	(1)	Form of Registration Rights Agreement by and between the Registrant and the selling stockholders

10.7	(1)	Escrow Agreement, dated as of July 2, 2008, by and among the Registrant, Strasbourger Pearson Tulcin Wolff, Inc. and Gottbetter & Partners, LLP

10.8	(1)	Placement Agency Agreement, dated as of November 15, 2007, by and between Crownbutte Wind Power LLC and Strasbourger Pearson Tulcin Wolff, Inc.

10.9	(1)	Memorandum of Understanding, dated as of July 15, 2006, by and between the Registrant and Manu Kalia

10.10	(1)	Employment Contract, dated as of September 15, 2008, by and between the Registrant and Manu Kalia

10.11	(1)	Employment Contract, dated as of November 27, 2007, by and between the Registrant and Ryan Fegley

10.12	(1)	Asset Purchase and Development Agreement, effective December 27, 2006, between Crownbutte Wind Power LLC and Gascoyne Wind LLC

10.13	(2)	Asset Purchase Agreement, effective September 30, 2008, between Crownbutte Wind Power LLC and Gascoyne Wind LLC

10.14	(1)	General Consulting Services Agreement, dated July 31, 2007, between Crownbutte Wind Power LLC and Montana-Dakota Utilities Co.

10.15	(1)	Wind Development Agreement, dated January 14, 2008, between Crownbutte Wind Power LLC and EverGreen Energy

Exhibit No.		Description

10.16	(1)	Gascoyne Wind Park Joint Venture Agreement, dated May 27, 2008, between Crownbutte Wind Power LLC and Westmoreland Power, Inc.

10.17	(1)	Asset Purchase Agreement, dated September 25, 2008, between Crownbutte Wind Power, Inc., a North Dakota corporation, and American Seawind Energy LLC

10.18	(1)	Form of Lease Option Agreement & Wind Energy Lease between the Registrant and a landowner

10.19	(2)	Employment Contract, dated as of September 17, 2008, by and between the Registrant and Terry Pilling

10.20	*	Promissory Note, dated as of March 29, 2010, in the principal amount of $100,000, issued by the Registrant to Catherine C. Coleman

10.21	*	Promissory Note, dated as of March 29, 2010, in the principal amount of $100,000, issued by the Registrant to David L. Cohen

21	(1)	Subsidiaries of the Registrant

31.1	*	Certification of Principal Executive Officer, pursuant to SEC Rules 13a-14(a) and 15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

31.2	*	Certification of Principal Financial Officer, pursuant to SEC Rules 13a-14(a) and 15d-14(a), adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

32.1	*	Certification of Chief Executive Officer, pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002†

32.2	*	Certification of Acting Chief Financial Officer, pursuant to 18 U.S.C. Section 1350, adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002†

(1)	Incorporated by reference to the like numbered Exhibit to the Registrant’s Amendment No. 1 to Registration Statement on Form S-1 (File No. 333-156467), filed with the SEC on April 24, 2009.

(2)	Incorporated by reference to the like numbered Exhibit to the Registrant’s Amendment No. 2 to Registration Statement on Form S-1 (File No. 333-156467), filed with the SEC on June 19, 2009.

* Filed herewith.

† This certification is being furnished and shall not be deemed “filed” with the SEC for purposes of Section 18 of the Exchange Act, or otherwise subject to the liability of that section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act or the Exchange Act, except if and to the extent that the Registrant specifically incorporates it by reference.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, as amended, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	CROWNBUTTE WIND POWER, INC.

Dated: April 15, 2010	By:	/s/ Timothy H. Simons
		Timothy H. Simons, Chief Executive Officer

	By:	/s/ Manu Kalia
		Manu Kalia, Chief Financial Officer

In accordance with the Exchange Act, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

SIGNATURE	TITLE	DATE

/s/ Timothy H. Simons	Director and Chief Executive	April 15, 2010
Timothy H. Simons	Officer (principal executive officer)

/s/ Manu Kalia	Chief Financial Officer (principal	April 15, 2010
Manu Kalia	financial officer and principal accounting officer)

/s/ Ross D. Mushik	Director	April 15, 2010
Ross D. Mushik

/s/ Terry Pilling	Director	April 15, 2010
Terry Pilling

INDEX TO FINANCIAL STATEMENTS

		Page

Reports of Independent Registered Public Accounting Firm		F-2

Consolidated Balance Sheets as of December 31, 2009 and 2008		F-3

Consolidated Statements of Operations for the years ended December 31, 2009 and 2008		F-4

Consolidated Statement of Changes in Stockholders’ Equity (Deficit) for the year ended December 31, 2009		F-5

Consolidated Statements of Cash Flows for the years ended December 31, 2009 and 2008		F-6

Notes to Consolidated Financial Statements		F-7

F-1

REPORTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Crownbutte Wind Power, Inc.

We have audited the accompanying consolidated balance sheets of Crownbutte Wind Power, Inc. as of December 31, 2009 and 2008 and the related consolidated statements of operations, stockholders’ equity and cash flows for the years then ended. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Accordingly we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Crownbutte Wind Power, Inc. as of December 31, 2009 and 2008 and the results of their operations and their cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.

The accompanying consolidated financial statements have been prepared assuming that the Company will continue as a going concern. The Company has incurred significant losses as more fully described in Note 2. These issues raise substantial doubt about the Company’s ability to continue as a going concern. Management’s plans in regard to these matters are also described in Note 2. The consolidated financial statements do not include any adjustments that might result from the outcome of this uncertainty.

/s/ Sherb & Co., LLP
Certified Public Accountants

New York, New York
April 15, 2010

F-2

CROWNBUTTE WIND POWER, INC.

Consolidated Balance Sheets

For the years ended December 31, 2009 and 2008

	December 31, 2009			December 31, 2008

ASSETS

Current Assets:
Cash and cash equivalents	$	17,322		$	304,703
Certificates of deposit		-			152,029
Other current assets		3,949			23,109
Total current assets		21,271			479,841

Other assets:
Interconnect application deposits		91,638			112,346
Property and equipment, net		166,088			234,357
Total other assets		257,726			346,703
	$	278,997		$	826,544

LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)

Current liabilities:
Accounts payable	$	371,297		$	128,683
Accrued expenses		239,886			50,958
Stockholder loan payable		20,000			-
Due to officer		42,380			-
Total current liabilities		673,563			179,641

Total liabilities		673,563			179,641

Stockholders’ equity (deficit):

Preferred stock, $0.001 par value, 25,000,000 shares authorized none issued and outstanding		-			-
Common stock, $0.001 par value, 300,000,000 shares authorized 31,300,331 and 26,200,331 issued and outstanding		31,300			26,200
Additional paid-in capital		5,113,209			4,336,606
Retained earnings deficit		(5,539,075	)		(3,715,903	)
Total stockholders’ equity (deficit)		(394,566	)		646,903

Total liabilities and stockholders’ equity (deficit)	$	278,997		$	826,544

See accompanying notes to audited consolidated financial statements.

F-3

CROWNBUTTE WIND POWER, INC.

Consolidated Statements of Operations

For the years ended December 31, 2009 and 2008

	For the years ended December 31,
	2009			2008

Sale of project development rights	$	-		$	200,000
Consulting revenues		-			73,020
Total revenues	$	-		$	273,020

Cost of revenues:
Project development rights		-			34,593
Consulting revenues		-			3,482
Total cost of revenues		-			38,075
Gross profit		-			234,945

Operating expenses:
General and administrative (includes stock based compensation of $702,702 and $2,739,974 in 2009 and 2008)		1,828,235			4,169,687
Depreciation expense		32,459			21,039
Total operating expenses		1,860,694			4,190,726

Net operating loss		(1,860,694	)		(3,955,781	)

Other income (expenses):
Interest income		935			11,282
Other income		60,772			-
Interest expense		(4,094	)		-
Bad debt expense		(1,722	)		-
Loss on sale of fixed assets		(18,369	)		-
Total other income (expenses)		37,522			11,282

Net loss	$	(1,823,172	)	$	(3,944,499	)

Basic and diluted - net loss per common share	$	(0.07	)	$	(0.20	)

Basic and diluted - weighted average common shares outstanding		26,595,947			20,019,294

See accompanying notes to audited consolidated financial statements.

F-4

CROWNBUTTE WIND POWER, INC.

Consolidated Statement of Changes in Stockholders’ Equity (Deficit)

For the year ended December 31, 2009

	Common Stock				Additional			Retained			Total Stockholders’
	($.001 par value)				Paid-In			Earnings			Equity
	Shares		Amount		Capital			(Deficit)			(Deficit)
Balance, December 31, 2007		17,000,000	$	17,000	$	(17,000	)	$	228,596		$	228,596

Shares effectively issued to former ProMana shareholders as part of the July 2, 2008 recapitalization		1,482,331		1,482		(1,482	)		-			-

Common stock and warrants issued for cash		4,218,000		4,218		1,618,615			-			1,622,833-

Conversion of warrants to common stock		3,500,000		3,500		(3,500	)		-			-

Stock-based compensation		-		-		2,739,974			-			2,739,974

Net loss		-		-		-			(3,944,499	)		(3,944,499	)

Balance, December 31, 2008		26,200,331	$	26,200	$	4,336,607		$	(3,715,903	)	$	646,904

Issuance of common stock for services		100,000		100		28,900			-			29,000

Exercise of 5,000,000 warrants		5,000,000		5,000		45,000			-			50,000

Stock-based compensation		-		-		702,702			-			702,702

Net loss		-		-		-			(1,823,172	)		(1,823,172	)

Balance, December 31, 2009		31,300,331	$	31,300	$	5,113,209		$	(5,539,075	)	$	(394,566	)

See accompanying notes to audited consolidated financial statements.

F-5

CROWNBUTTE WIND POWER, INC.

Consolidated Statements of Cash Flows

For the years ended December 31, 2009 and 2008

	For the years ended December 31,
	2009			2008
Cash flows from operating activities:
Net loss	$	(1,823,172	)	$	(3,944,499	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation		32,459			21,039
Bad debt		1,722			-
Stock issued for services		29,000			-
Warrants exercised for services		8,357			-
Stock-based compensation		702,702			2,739,974
Loss on sale of fixed assets		18,369			-
Changes in operating assets and liabilities:
Decrease (increase) in:
Other assets		38,147			(125,102	)
Increase in:
Accounts payable		245,467			122,246
Accrued expenses		186,074			27,441
Total adjustments		1,262,297			2,785,598
Net cash used in operating activities		(560,875	)		(1,158,901	)

Cash flows from investing activities:
Certificates of deposit redeemed		152,030			140,889
Investment in certificates of deposit		-			(152,030	)
Purchase of fixed assets		(5,259	)		(170,499	)
Proceeds from sale of fixed assets		22,700			-
Net cash provided by (used in) investing activities		169,471			(181,640	)

Cash flows from financing activities:
Net proceeds of private placement		-			1,622,833
Proceeds from exercise of warrants		41,643			-
Deferred financing costs		-			50,000
Payment of dividends		-			(153,333	)
Proceeds from stockholder loan		20,000			-
Proceeds from officer loan		44,380			-
Payments on officer loan		(2,000	)		-
Net cash provided by financing activities		104,023			1,519,500

Net increase (decrease) in cash and cash equivalents		(287,381	)		178,959

Cash and cash equivalents, beginning of period		304,703			125,744

Cash and cash equivalents, end of period	$	17,322		$	304,703

Supplemental disclosures of cash flow information:
Cash paid during the year for:
Interest paid	$	4,094		$	-
Taxes paid	$	119		$	-

See accompanying notes to audited consolidated financial statements.

F-6

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

NOTE 1 – ORGANIZATION, DESCRIPTION OF BUSINESS AND MERGER

Crownbutte Wind Power LLC (“Crownbutte ND”) was founded on May 11, 1999 with the strategy of addressing the requirements of regional utility companies to satisfy increasing renewable energy demands. Crownbutte ND was formed as a limited liability company (LLC) in the State of North Dakota and elected to be taxed as an S corporation effective January 1, 2001. On March 11, 2008, Crownbutte ND no longer met the requirements to be treated as an S corporation. As a result, effective March 11, 2008, Crownbutte ND has been taxed like a C corporation. On May 19, 2008, Crownbutte ND filed with the Secretary of State of North Dakota to convert from an LLC to a C corporation becoming “Crownbutte Wind Power, Inc.” On July 2, 2008, Crownbutte ND became a wholly owned subsidiary of Crownbutte Wind Power, Inc., a Nevada corporation, formerly ProMana Solutions, Inc. as described below.

In cooperation with a local utility, Crownbutte developed and constructed the first utility-scale wind facility in either of the Dakotas in 2001, consisting of two turbines near Chamberlain, South Dakota.

The Company currently functions as a wind park developer as well as a consulting and advisory service to power utilities.

ProMana Solutions, Inc. (or “ProMana”)

ProMana was incorporated in the State of Nevada on March 9, 2004, under the name ProMana Solutions, Inc. ProMana’s business was to provide web-based, fully integrated solutions for managing payroll, benefits, human resource management and business processing outsourcing to small and medium sized businesses. Following the merger described below, ProMana is no longer in that web services business. On July 2, 2008, ProMana amended its Articles of Incorporation to change its name to Crownbutte Wind Power, Inc.

Merger

On July 2, 2008, pursuant to a Merger Agreement entered into on the same date, Crownbutte Acquisition Sub Inc., a North Dakota corporation formed on June 6, 2008, and a wholly owned subsidiary (“Acquisition Sub”), merged with and into Crownbutte ND, with Crownbutte ND being the surviving corporation (the “Merger”). As a result of the Merger, Crownbutte ND became a wholly-owned subsidiary of the Company.

Pursuant to the Merger, ProMana ceased operating as a provider of web-based, fully integrated solutions for managing payroll, benefits, human resource management and business processing outsourcing, and acquired the business of Crownbutte ND to develop wind parks from green field to operation and has continued Crownbutte ND’s business operations as a publicly-traded company. See “Split-Off Agreement” below.

At the closing of the Merger, each share of Crownbutte ND’s common stock issued and outstanding immediately prior to the closing of the Merger was converted into one share of the Company’s common stock. As a result, an aggregate of 18,100,000 shares of common stock were issued to the holders of Crownbutte ND’s common stock, 17,000,000 of which were issued to the original members of Crownbutte Wind Power LLC and 1,100,000 to investors in Crownbutte ND who purchased shares in a private placement prior to the merger. In addition, warrants to purchase an aggregate of 10,600,000 shares of Crownbutte ND’s outstanding at the time of the Merger became warrants to purchase an equivalent number of shares of the Company’s common stock.

Split-Off Agreement

Upon the closing of the Merger, under the terms of a Split-Off Agreement, ProMana transferred all of its pre-Merger operating assets and liabilities to its wholly-owned subsidiary, ProMana Technologies, Inc., a New Jersey corporation (“ProMana NJ”). Simultaneously, pursuant to the Split-Off Agreement, ProMana transferred all of the outstanding shares of capital stock of ProMana NJ to two stockholders prior to the Merger (the “Split-Off”), in consideration of and in exchange for (i) the surrender and cancellation of an aggregate of 144,702 shares of the common stock and warrants to purchase 19,062 shares of common stock held by those stockholders and (ii) certain representations, covenants and indemnities.

F-7

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

Stock Split

The Board of Directors authorized a one-for-65.723 reverse split of the Company’s common stock (the “Stock Split”), which was effective on July 31, 2008, for holders of record on July 14, 2008. After giving effect to the Stock Split, there were outstanding 19,582,249 shares of common stock. All share and per share numbers in this Report relating to the Common Stock prior to the Stock Split have been adjusted to give effect to the Stock Split retroactively unless otherwise stated.

For accounting purposes, the Merger was treated as a recapitalization of the Company. Crownbutte ND formerly Crownbutte Wind Power LLC is considered the acquirer for accounting purposes, and the Company’s historical financial statements before the Merger have been replaced with the historical financial statements of Crownbutte ND before the Merger in all subsequent filings with the Securities and Exchange Commission (the “SEC”).

As used herein, unless the context otherwise requires, the “Company” and “Crownbutte” refer to Crownbutte ND for periods prior to the merger and to Crownbutte Wind Power, Inc., a Nevada corporation, formerly ProMana Solutions, Inc., and its wholly-owned subsidiary, Crownbutte ND, for periods after the Merger.

NOTE 2 – BASIS OF PRESENTATION, CONSOLIDATION AND GOING CONCERN

The accompanying audited consolidated financial statements include the results of operations of the Company and its subsidiary for the years ended December 31, 2009 and 2008. All material intercompany accounts and transactions between the Company and its subsidiary have been eliminated in consolidation.

Certain reclassifications have been made to prior year amounts to conform to the current year presentation.

Going Concern

These consolidated financial statements have been prepared by management in accordance with accounting principles generally accepted in the United States on a “going concern” basis, which presumes the Company will be able to realize its assets and discharge its liabilities in the normal course of business for the foreseeable future.

The Company has incurred operating losses and negative cash flows from its operating activities for the year ended December 31, 2009, as well as an accumulated deficit of approximately $5,539,075 as of December 31, 2009 and a working capital deficit of $652,292.

As of December 31, 2009, the Company has only $17,322 in cash. The Company’s ability to pay its obligations as they become due is in danger as it is in need of immediate financing. The Company’s continued existence is dependent upon its ability to resolve its liquidity problems, principally by obtaining equity and or debt financing. The Company’s current operations are not an adequate source of cash to fund future operations. In the event that it is unable to obtain debt or equity financing, it may have to cease or curtail operations.

The Company’s management continues to focus on procurement of financing for its Gascoyne I project and is actively engaged in discussion with parties who may be interested in purchasing development rights of some of the Company’s other greenfield projects.

The Company’s ability to continue as a going concern is dependent upon either the sale of one or more greenfield projects, obtaining additional financing to develop the properties and the ultimate realization of profits through future production or sale of properties, and the success of the Company’s business plan. The outcome of these matters cannot be predicted at this time. These consolidated financial statements do not include any adjustments to the amounts and classifications of assets and liabilities that might be necessary should the Company be unable to continue its business.

F-8

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

NOTE 3 — SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Revenue Recognition

Cost of Revenues

Estimates

The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect certain reported amounts and disclosures. Accordingly, actual results could differ from those estimates.

Cash and Cash Equivalents and Certificates of Deposit

For purpose of reporting cash flows, the Company considers all accounts with maturities of three months or less to be cash equivalents. Certificates of deposit with a maturity of more than three months when purchased are classified as current assets.

F-9

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

At December 31, 2008, the Company had certificates of deposit in the amounts of $100,000 and $52,030 which collected interest of 2.68% and 3.21% and matured on February 26, 2009 and May 13, 2009, respectively.

Property, Equipment and Leasehold Improvements

Property, equipment and leasehold improvements are stated at cost. The Company records straight-line depreciation based on the estimated useful life of the individual units of property and equipment. Estimated useful lives are five to ten years for the property and equipment. Leasehold improvements are amortized using the straight-line method over the shorter of the estimated useful lives of the assets or the terms of the leases.

Research and Development

The Company expenses research and development as incurred.

Income Taxes

The Company was organized as a limited liability company for the year ended December 31, 2007 and the Company’s members elected to be taxed as an S corporation. An S corporation is not a taxpaying entity for federal and state income tax purposes; thus, no income tax expenses have been recorded in the financial statements. It is the responsibility of the members to report their proportionate share of the Company’s income or loss on the members’ individual income tax returns.

Since March 11, 2008, the Company is being taxed as a C corporation. A short year S corporation tax return and a short year C corporation tax return was filed. Income tax liability for the years ended December 31, 2009 and 2008 is $0.

Income taxes are accounted for in accordance with the provisions of FASB ASC 740, Accounting for Income Taxes. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date. Valuation allowances are established, when necessary, to reduce deferred tax assets to the amounts expected to be realized.

Customer Concentration

Two of the Company’s customers accounted for 100% of its revenues for the year ended December 31, 2008. The Company had no revenues for the year ended December 31, 2009.

Concentration of Credit Risk

The Company maintains its cash deposits at various financial institutions. Bank balances periodically exceed the Federal Deposit Insurance Corporation limits at one bank.

Fair Value of Financial Instruments

Effective January 1, 2008, the Company adopted guidance issued by the Financial Accounting Standards Board (“FASB”) on “Fair Value Measurements” for assets and liabilities measured at fair value on a recurring basis. This guidance establishes a common definition for fair value to be applied to existing generally accepted accounting principles that require the use of fair value measurements establishes a framework for measuring fair value and expands disclosure about such fair value measurements. The adoption of this guidance did not have an impact on the Company’s financial position or operating results, but did expand certain disclosures.

F-10

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

The Financial Accounting Standards Board (“FASB”) defines fair value as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Additionally, the “FASB” requires the use of valuation techniques that maximize the use of observable inputs and minimize the use of unobservable inputs. These inputs are prioritized below:

Level 1:

Observable inputs such as quoted market prices in active markets for identical assets or liabilities

Level 2:

Observable market-based inputs or unobservable inputs that are corroborated by market data

Level 3:

Unobservable inputs for which there is little or no market data, which require the use of the reporting entity’s own assumptions.

The Company did not have any Level 2 or Level 3 assets or liabilities as of December 31, 2009 and December 31, 2008. The Company discloses the estimated fair values for all financial instruments for which it is practicable to estimate fair value. As of December 31, 2009 and December 31, 2008, the fair value short-term financial instruments including cash, certificates of deposit, other current assets, accounts payable, accrued expenses and due to officer, approximates book value due to their short-term duration.

Cash and cash equivalents include money market securities and commercial paper that are considered to be highly liquid and easily tradable. These securities are valued using inputs observable in active markets for identical securities and are therefore classified as Level 1 within the fair value hierarchy.

In addition, the Financial Accounting Standards Board (“FASB”) issued, “The Fair Value Option for Financial Assets and Financial Liabilities,” effective for January 1, 2008. This guidance expands opportunities to use fair value measurements in financial reporting and permits entities to choose to measure many financial instruments and certain other items at fair value. The Company did not elect the fair value option for any of its qualifying financial instruments.

Stock-Based Compensation

For the years ended December 31, 2009 and 2008, the Company recorded stock-based compensation of $702,702 and $2,739,974, respectively.

Basic and Diluted Earnings per Share

Basic earnings per share are calculated by dividing income available to stockholders by the weighted average number of common shares outstanding during each period. Diluted earnings per share are computed using the weighted average number of common and dilutive common share equivalents outstanding during the period. Dilutive common share equivalents consist of shares issuable upon the exercise of stock options and warrants (calculated using the modified-treasury stock method). The outstanding warrants amounted to 7,235,752 and 10,235,752 at December 31, 2009 and 2008, respectively. For the years ended December 31, 2009 and 2008, these potentially dilutive securities were not included in the calculation of loss per share because the Company incurred a loss during such periods and thus their effect would have been anti-dilutive.

New Accounting Pronouncements

F-11

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

Management’s responsibility for establishing and maintaining adequate internal control over its financial reporting;

Management’s assessment of the effectiveness of its internal control over financial reporting as of year- end; and

The framework used by management to evaluate the effectiveness of the Company’s internal control over financial reporting.

F-12

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

F-13

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

NOTE 4 – PROPERTY, EQUIPMENT AND LEASEHOLD IMPROVEMENTS

Property and equipment and related accumulated depreciation consists of the following:

	December 31, 2009			December 31, 2008
Equipment and Vehicles	$	179,370		$	229,495
Software		39,289			39,289
Leasehold Improvements		938			-
Total Cost		219,597			268,784
Accumulated Depreciation		(53,509	)		(34,427	)
Net Property and Equipment	$	166,088		$	234,357

Equipment and vehicles are depreciated with an estimated useful life of 5 to 10 years and software has an estimated useful life of 5 years. Depreciation expense was $32,459 and $21,039 for the years ended December 31, 2009 and 2008, respectively.

NOTE 5 – ACCRUED EXPENSES

Accrued expenses consist of the following:

	December 31, 2009		December 31, 2008
Accrued Payroll	$	216,254	$	45,984
Credit Cards Payable		23,262		-
Accrued Vacation		324		-
Accrued Interest		46		-
Payroll Taxes Payable		-		2,663
Sales Tax Payable		-		2,311
	$	239,886	$	50,958

NOTE 6 – STOCKHOLDERS’ EQUITY (DEFICIT)

Under the terms of the merger the Company issued 17,000,000 shares of common stock and 1,000,000 warrants to the two original members of Crownbutte ND (formerly “Crownbutte Wind Power LLC”) and 1,482,331 shares of common stock to the pre-merger ProMana shareholders.

To appropriately reflect this recapitalization, the Company has retroactively restated the equity of the Company prior to the merger date to include the 17,000,000 shares of common stock and 1,000,000 warrants issued to the two original members of Crownbutte ND (formerly “Crownbutte Wind Power LLC”) in the merger.

During the period from March 11, 2008 through September 8, 2008, the Company completed its private placement to accredited investors for $2,109,000 (net proceeds of $1,622,833) in units of its securities consisting of 4,218,000 shares of common stock at a purchase price of $0.50 per share and common stock purchase warrants to purchase 4,218,000 shares of common stock.

F-14

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

During the years ended December 31, 2009 and 2008, the Company issued 5,000,000 and 3,500,000 shares of common stock, respectively, for the exercise of 5,000,000 and 3,500,000 warrants.

During the year ended December 31, 2009, the Company issued 100,000 shares of common stock for legal services. These shares were valued at $0.29 per share, the fair market value at the date of issuance. Accordingly, the Company recorded legal expense of $29,000.

Stock Purchase Warrants

During the year ended December 31, 2008, the Company issued 15,718,000 warrants at exercise prices ranging from $0.001 and $2.50 per common share as follows:

In connection with the merger the Company issued 1,000,000 warrants to one of the original members of Crownbutte, ND (formerly Crownbutte Wind Power LLC) to purchase up to 1,000,000 shares of common stock of the Company at an exercise price of $.10 per share. The warrants have a term of 5 years after the issuance date of July 2, 2008.

In connection with private placements a total of 4,218,000 warrants were issued to purchase up to 4,218,000 shares of common stock of the Company with 1,100,000 warrants at an exercise price of $0.50 per share and 3,118,000 warrants at an exercise price of $2.50 per share. The 1,100,000 warrants have a term of 3 years after the issuing date and the 3,118,000 warrants have a term of 2 years after the issuing date. The warrants will be callable by the Company at any time if the fair market value of the common stock for the twenty (20) consecutive trading days ending three days prior to the date of the call notice is at least $3.50. Additionally, the Company issued 3,500,000 to the placement agent at an exercise price of $0.001 per share. These warrants were exercised during the year ended December 31, 2008.

During the year ended December 31, 2008, the Company granted 7,000,000 warrants to purchase 7,000,000 shares of the common stock of the Company. The warrants included 2,000,000 awarded to the Chief Financial Officer at an exercise price of $0.001 per share which vest over the next twelve months and 5,000,000 awarded to the Vice President of Project Development at an exercise price of $0.01 per share which vest immediately. The warrants were issued at an exercise price significantly less than the offering price of $0.50. During the year ended December 31, 2009, the 5,000,000 warrants originally awarded to the Vice President of Project Development were exercised.

The Company valued these warrants utilizing the Black-Scholes options pricing model and the following assumption terms: 3 to 5 years; interest rate: 4%; volatility: 100%. For the year ended December 31, 2008, the Company recorded compensation expense of approximately $2,700,000 related to the warrants. This amount represents 100% of the value of the 5,000,000 warrants which vested immediately and 25% of the 2,000,000 warrants vested by December 31, 2008.

The 2,000,000 warrants granted to the CFO were valued at approximately $1,000,000. This amount was expensed over the vesting period. For the year ended December 31, 2009 the Company expensed approximately $700,000 related to these warrants which became fully vested by September 15, 2009.

F-15

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

A reconciliation of warrant activity is as follows:

	Number of Shares Issuable			Weighted Average Exercise Price		Weighted Average Grant Date Fair Value
Balance at January 1, 2008		17,752	*	$	0.65723	$	0.35
Granted		15,718,000			0.68		0.35
Exercised		(3,500,000	)		0.001		0.50
Expired		-			-		-
Balance at December 31, 2008		12,235,752		$	0.87	$	0.35

Balance at January 1, 2009		12,235,752		$	0.87	$	0.35
Granted		-			-		-
Exercised		(5,000,000	)		0.01		0.49
Expired		-			-		-
Balance at December 31, 2009		7,235,752		$	1.17	$	0.25

Warrants outstanding and exercisable at December 31, 2009 have a weighted average exercise price of $1.17 and an intrinsic value of $738,000. At December 31, 2008, the warrants exercisable had a weighted average exercise price of $0.78 and an aggregate intrinsic value of $2,850,000. The weighted average exercise price of warrants outstanding at December 31, 2008 was $0.87 with an aggregate intrinsic value of $3,848,000.

The following tables summarize warrants outstanding and exercisable as of December 31, 2009 and 2008:

Exercise Price	Number of shares underlying Warrants		Weighted- average remaining contractual life (in Years)		Number of shares exercisable		Weighted- average remaining contractual Life of Warrants Exercisable (in Years)
$ 0.001		2,000,000		3.71		2,000,000		3.71
$ 0.10		1,000,000		3.50		1,000,000		3.50
$ 0.50		1,100,000		1.25		1,100,000		1.25
$ 0.65723		17,752		*		17,752		*
$ 2.50		3,118,000		.46		3,118,000		.46
Balance at December 31, 2009		7,235,752		1.78		7,235,752		1.78

F-16

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

Exercise Price	Number of shares underlying Warrants		Weighted- average remaining contractual life (in Years)		Number of shares exercisable		Weighted- average remaining contractual Life of Warrants Exercisable (in Years)
$ 0.001		2,000,000		4.71		-		-
$ 0.01		5,000,000		2.50		5,000,000		2.50
$ 0.10		1,000,000		4.50		1,000,000		4.50
$ 0.50		1,100,000		2.25		1,100,000		2.25
$ 0.65723		17,752		*		17,752		*
$ 2.50		3,118,000		1.46		3,118,000		1.46
Balance at December 31, 2008		12,235,752		2.66		10,235,752		2.26

*These warrants were issued by ProMana prior to the merger. The Company is unable to identify the remaining contractual life of these warrants.

The total intrinsic value of warrants exercised for the years ended December 31, 2009 and 2008 was $1,350,000 and $1,746,500, respectively.

NOTE 7 – INCOME TAXES

The Company has a net operating loss carry forward for tax purposes totaling approximately $964,000 at December 31, 2009. The net operating loss carries forward for income taxes, which may be available to reduce future years’ taxable income. These carry forwards will expire, if not utilized, through 2029 and are subject to the Internal Revenue Code Section 382, which places a limitation on the amount of taxable income that can be offset by net operating losses after a change in ownership. Management believes that the realization of the benefits from these losses appears uncertain due to the Company’s continuing losses for income tax purposes. Accordingly, the Company has provided a 100% valuation allowance on the deferred tax asset benefit to reduce the asset to zero. Management will review this valuation allowance periodically and make adjustments as warranted.

The table below summarizes the differences between the Company’s effective tax rate and the statutory federal rate as follows for the year ended December 31, 2009 and the period ended December 31, 2008:

Rate Reconciliation:	December 31, 2009			December 31, 2008

Expected Federal income tax benefit (at 34%)	$	(637,971	)	$	(1,341,300	)
State tax benefit (net of Federal effect)		(75,055	)		(157,800	)
Loss incurred during S corp period		-			239,020
Other		380			760
Change in valuation allowance		712,646			1,259,320
Net income tax benefit	$	-		$	-

Deferred tax assets and liabilities are provided for significant income and expense items recognized in different years for tax and financial reporting purposes. Temporary differences, which give rise to a net deferred tax asset is as follows:

F-17

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

Schedule of deferred tax assets	December 31, 2009			December 31, 2008

Net operating loss	$	366,466		$	211,660
Temporary differences: Depreciation		8,740			6,460
Warrant expense		267,140			1,041,200
Accrued expenses not paid within 2 ½ months		70,300			-
Valuation allowance		(712,646	)		(1,259,320	)
Net deferred tax asset	$	-		$	-

NOTE 8 – RELATED PARTY TRANSACTIONS

The Company borrowed funds from Timothy Simons, one of the Company’s stockholders and its CEO. The terms of the loans are non-interest bearing and payable upon demand. Amounts owed totaled $42,380 as of December 31, 2009 and $0 for the year ended December 31, 2008.

The Company borrowed funds from StarInvest Group, Inc., one of the Company’s stockholders. Terms of the loan are $20,000 at 6% annual interest, due within one year. The date of the loan is December 18, 2009. As of December 31, 2009, the Company owed $20,000.

The Company leased office space from Timothy Simons, one of the Company’s stockholders and its CEO. The lease was a month-to-month lease for $458 per month. The lease terminated on March 31, 2008. Total rent expense paid for the year ended December 31, 2008 was $1,374.

NOTE 9 – OFFICE AND SHOP LEASE

On May 1, 2008, the Company entered into a lease for office and shop space at $1,500 per month. The lease is for twelve months and has no renewal options. Upon expiration of the initial lease term, the lease is month-to-month. The Company is responsible for paying all utilities and janitorial.

NOTE 10 – RETIREMENT PLAN

In August 2007, the Company established a SIMPLE retirement plan. The Company matches employee contributions up to 3% of gross wages. The Company’s contributions to the plan were $5,141 and $7,469 for the years ended December 31, 2009 and 2008, respectively.

NOTE 11 – CONCENTRATION OF RISK

The Company conducted all of its operations for the years ended December 31, 2009 and 2008 under contracts with two companies, a utility and a coal company. Revenues earned and recognized for the years ended December 31, 2009 and 2008 were $0 and $273,020 for sale of project development rights ($200,000) and consulting revenue ($73,020), respectively.

NOTE 12 – PROJECT DEVELOPMENT COSTS AND INTERCONNECT APPLICATION DEPOSITS

The Company expenses all project development costs until management deems a project probable of being technically, commercially, and financially viable. The Company capitalizes project development costs generally once management deems a project probable of being technically, commercially, and financially viable. This generally occurs in tandem with management’s determination that a project should be classified as an advanced project, such as when favorable results of a system impact study are received, interconnect agreements obtained, and project financing is in place.

F-18

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

On May 27, 2008, the Company entered into a joint venture agreement with Westmoreland Power, Inc., a coal company, under the name of Gascoyne II Wind Project to develop, construct, manage, and operate a 200 MW wind power project in southwest North Dakota. The Company received $200,000 from Westmoreland as compensation in order to participate in the joint venture. The Company recognized sale of development rights revenues for this amount for the year ended December 31, 2008. Crownbutte is the managing party. For the years ended December 31, 2009 and 2008, the Company expensed development costs of $11,130 and $5,126, respectively, for this project.

On June 20, 2008, the Company entered into an agreement with a wind development company to purchase the rights to develop a wind park near New England, ND for $100,000. Assets purchased by the Company consist of one met tower, 3.5 years meteorological data, and a land lease cooperation agreement. For the years ended December 31, 2009 and 2008, the Company expensed development costs of $13,901 and $89,427, respectively, for this project.

On September 18, 2008, the Company entered into an agreement with a wind development company to purchase the rights to develop a 10 MW wind park near Ralls, TX for $1,500,000. The agreement calls for a non-refundable down payment of $200,000, another payment of $1,000,000 by March 10, 2009, and a final payment of $300,000 upon beginning construction of the wind park, but no later than September 18, 2009. Assets purchased by the Company consist of meteorological data, land lease option agreements, permits, licenses, assignable interconnect agreement, right-of-ways to substations and power lines, and FFA determination. Should the Company default on any payments, the seller would be entitled to take back the assets purchased by the Company. As of December 31, 2008 the Company expensed development costs totaling $210,270 for this project.

In 2008, the Company decided to repurchase the project. On September 30, 2008 the Company entered into an agreement with the wind development company to repurchase the development rights for the 20 MW Gascoyne, ND wind park for $325,000. For the years ended December 31, 2009 and 2008, the Company expensed development costs totaling $93,667 and $333,476, respectively, for this project as it has not yet deemed the project probable of being technically, commercially, and financially viable.

For the years ended December 31, 2009 and 2008 the Company expensed an additional $38,178 and $282,799, respectively, in development costs for smaller projects not listed above.

The Company has deemed all of the projects described above as research and development costs which have been expensed accordingly.

Interconnect Application Deposits

The Company pays in advance for electrical interconnect studies. As the studies are performed, the portions of the advances that are used are expensed. These costs are incurred as part of the process to obtain an interconnect agreement. Interconnect deposits are classified as non-current assets as studies generally exceed one year in length. If a study is complete, any unused deposits are refunded to the Company. At December 31, 2009 and December 31, 2008, the Company had $91,638 and $112,346, respectively, of unused deposits on its balance sheet.

F-19

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

NOTE 13 – COMMITMENTS AND CONTINGENCIES

On September 15, 2008, the Company entered into an employment contract with a new CFO. The contract calls for a starting annual salary of $100,000. Once an additional $3,000,000 is raised from the private placement, the annual salary will increase to $150,000. There is no specified termination date of employment in the contract.

Legal proceedings

On August 19, 2008, Centre Square Capital, LLC filed a claim in the amount of $3,000,000 plus attorneys fees, interest, and arbitration costs in a demand for arbitration, claiming that the Company has not compensated it for introducing the Company to the firm that raised the private placement capital in March, 2008 and thereafter. On March 16, 2009 a judge dismissed Centre Square Capital LLC’s claim and awarded the Company reimbursement of all attorney fees and costs related to the claim. A reimbursement of approximately $129,227 is payable to the Company.

The Company accounts for awards of attorney fees and costs resulting from judgments in its favor on a case-by-case basis. Factors affecting the accounting treatment include timing of expenses incurred and date of award, likelihood of collection, and additional costs incurred in the collection process. Judgments awarded that management deems collectible are recorded as a receivable. Award amounts for expenses incurred in the same accounting period are recorded as reductions in the corresponding expense line item. Reimbursements of prior period expenses are recorded as other income. Collection of the Centre Square Capital judgment is uncertain and accordingly, no receivable has been recorded. For the year ended December 31, 2009 the Company collected $0 of this award.

On November 3, 2009, the Company was served with a lawsuit filed against us in the Philadelphia County Court of Common Pleas under Case ID: 091100318. Stradley, Ronon, Stevens & Young, LLP (the plaintiffs) filed a claim against the Company for nonpayment of legal fees and are seeking to recover $93,526 plus interest, attorneys’ fees and costs. This claim arose as a result of legal services provided in the Centre Square Capital, LLC arbitration claim filed August 19, 2008. The Company has included the $93,526 in accounts payable as of December 31, 2009.

On December 14, 2009, the Company received a Notice of Intent to Take Default Judgment from Stradley, Ronon, Stevens & Young, LLP for the unpaid balance of $93,526. The Company has been working with the plaintiff to make payments on the debt. In exchange, the plaintiffs have agreed to postpone execution of the judgment.

NOTE 14 – SUBSEQUENT EVENTS

In accordance with ASC 855, “Subsequent Events,” the Company evaluated subsequent events after the balance sheet date of December 31, 2009 through April 15, 2010, which is the date the financial statements were issued.

On February 15, 2010, the Company executed a non-binding term sheet with iStreet Global, a private equity firm, to provide $37.5 million debt financing for the Gascoyne I project. The Company will retain 20% ownership and profit-sharing in the project. Terms of the financing are $14 million to be repaid over five years at prime plus 4%, 7% floor capped at 10% and $23.5 million repaid over five years at prime plus 6%, 9% floor capped at 12%. Both loans are interest only for the first twelve months. The lender intends to refinance the $23.5 million loan into a 15 year termed facility either through external funding or internally if no external sources are available. The deal is contingent upon final approval of iStreet Global after completion of due diligence. The Company anticipates a closing date of in the second quarter of 2010.

On February 22, 2010, the Company Board of Directors executed a Unanimous Written Consent approving a private placement transaction to offer investors a minimum of $150,000 (428,571 shares) and a maximum of $700,000 (2,000,000 shares) of the Company’s common stock at $0.35 per share. Each share sold will include one warrant to purchase one share of the Company’s common stock exercisable for a period of four years at an exercise price of $1.50 per share, and one warrant to purchase one share of common stock, exercisable for four years, at an exercise price of $2.50 per share. The Company issued 499,999 shares and 999,998 warrants for proceeds of $175,000.

F-20

CROWNBUTTE WIND POWER, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2009 and 2008

On February 24, 2010, the $20,000 short-term note payable to StarInvest Group, Inc. was converted to common stock as part of the private placement. A total of 57,142 shares and 114,284 warrants were issued as a result of the conversion of the promissory note. After this transaction, the Company has issued an aggregate of 557,141 shares of common stock and 1,114,282 warrants in the private placement.

F-21

Attached files

Crownbutte Wind Power, Inc. Reports

Also read